Exhibit 99.1

Message to shareholders

Cenovus Energy, a Canadian integrated oil company, was successfully launched on December 1, 2009 when EnCana Corporation split into two highly focused and independent publicly traded energy companies.

Since Cenovus was only in existence for one month last year, we have produced this abbreviated report for 2009. It includes Cenovus’s Audited Financial Statements and Management’s Discussion and Analysis for the year ended December 31, 2009. Given that Cenovus’s assets were held by EnCana Corporation until November 30, 2009, our financial and production information has been derived from the accounting records of EnCana on a carve-out accounting basis for the periods prior to December 1, 2009.

Additionally, in light of being a new company, the TSX has granted Cenovus an exemption from the requirement to hold our first annual meeting of shareholders within six months of December 31, 2009. As a result, our first annual meeting of shareholders is expected to occur in the second quarter of 2011, but no later than May 31, 2011.

On behalf of the Cenovus management team and Board of Directors, thank you for your continued support. We look forward to sharing with you the new thinking that we are bringing to our development of energy resources. A brochure highlighting our major projects, the enhancements we’ve made to the technology we use, and our growth plans for the company will be ready later this year. If you’re interested in receiving a copy, please contact us at investor.relations@cenovus.com or the address indicated on page 94 of this report. We also invite you to visit our website at www.cenovus.com to find out more about Cenovus.

Kerry D. Dyte
Executive Vice-President,
General Counsel & Corporate Secretary

MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (“Cenovus” or “the Company”) should be read with the audited Cenovus Energy Inc. Consolidated Financial Statements for the year ended December 31, 2009 (the “Consolidated Financial Statements”) as well as EnCana Corporation’s (“EnCana”) Information Circular Relating to an Arrangement Involving Cenovus Energy Inc. (the “Information Circular”) dated October 20, 2009. Readers should also read the “Forward-Looking Statements” legal advisory contained at the end of this document and such similar legal advisories contained in the Information Circular. Management is responsible for preparing the MD&A, while the audit committee of the Board of Directors of Cenovus (the “Board”) reviews the MD&A and recommends its approval by the Board. The Consolidated Financial Statements and comparative information have been prepared in United States (“U.S.”) dollars, except where another currency has been indicated, and in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). Production and reserves volumes are presented on an after royalties basis consistent with U.S. protocol reporting. This document is dated February 17, 2010. Readers can find the definition of certain terms used in this document in the disclosure regarding Oil and Gas Information and Currency, Non-GAAP Measures and References to Cenovus contained in the Advisory section located at the end of this document, and such similar advisories set out in the Information Circular.

INTRODUCTION AND OVERVIEW OF CENOVUS ENERGY

Cenovus is an integrated oil company headquartered in Calgary, Alberta. Our operations include enhanced oil recovery (“EOR”) properties and established crude oil and natural gas production in Alberta and Saskatchewan. We also have ownership interests in two refineries in Illinois and Texas, USA.

We began independent operations on December 1, 2009 following the Arrangement with EnCana Corporation which created two independent publicly traded energy companies — Cenovus and EnCana (the “Arrangement”). Although we are a new company, we have operated a number of assets for decades.

Our operations include our technology-driven EOR properties, coupled with established crude oil and natural gas production in Alberta and Saskatchewan. Three of our four enhanced oil properties (Foster Creek, Christina Lake and Pelican Lake) are located in the Athabasca region in northeast Alberta. The fourth, the Weyburn carbon dioxide (“CO₂”) sequestration EOR project, is located in southeastern Saskatchewan. We also have a 50 percent ownership interest in two refineries in Illinois and Texas, USA, enabling us to capture the full value from crude oil production through to refined products such as gasoline, diesel and jet fuel.

Our operational focus over the next five years will be to increase production predominantly from our steam-assisted gravity drainage (“SAGD”) operations at Foster Creek and Christina Lake. We have proven our expertise and low cost EOR development approach. Our established crude oil and natural gas production base is expected to generate stable production and cash flows which will enable further development of our core bitumen assets. In all our operations, whether bitumen, crude oil or natural gas, technology plays a key role in extracting the resource, increasing the amount recovered, reducing costs and improving the way we extract the resources. One of our most significant ongoing objectives is to advance technologies that reduce the amount of water, steam, natural gas and electricity consumed in our operations and to minimize surface land disturbance.

Our future lies in developing the vast land position we hold in the Athabasca region in northeast Alberta. In addition to our Foster Creek and Christina Lake properties, we currently have two emerging properties in this area: Borealis and Narrows Lake. A joint application to the Energy Resources Conservation Board and Alberta Environment for the development of Borealis has been submitted for the construction of a SAGD facility with production capacity of 35,000 barrels (“bbls”) of bitumen per day. We hold a 50 percent interest in the Narrows Lake play, through our interest in the FCCL Partnership, which is located within the greater Christina Lake regional area. We are preparing development plans and regulatory applications for a project at Narrows Lake that would include two to three phases with each phase expected to add approximately 40,000 barrels per day (“bbls/d”) of bitumen production capacity.

We have a number of opportunities to deliver shareholder value, predominantly through production growth from our extensive bitumen resource. Most of the bitumen resource is undeveloped and the resource is currently expected to assist in meeting consumer demand for decades to come. Growth at these enhanced oil operations is expected to be internally funded through cash flow generated from our established crude oil and natural gas production base. Our natural gas production also provides a natural economic hedge for the natural gas required as a fuel source at our upstream and downstream operations. Our low-cost refineries operated by ConocoPhillips, an unrelated U.S. public company, enable us to integrate our bitumen production with the sale of refined products.



Cenovus Energy Inc.		2
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

OUR BUSINESS STRUCTURE

Our operations are organized into two operating divisions:

•

Integrated Oil Division, which includes all of the assets within the upstream and downstream integrated oil business with our joint venture partner, as well as other bitumen interests and the Athabasca natural gas assets. The Integrated Oil Division has assets in both Canada and the U.S. including two major enhanced oil recovery properties: (i) Foster Creek; and (ii) Christina Lake; as well as two refineries: (i) Wood River; and (ii) Borger.

•

Canadian Plains Division, which contains established crude oil and natural gas development assets in Alberta and Saskatchewan and includes two major enhanced oil recovery properties: (i) Weyburn; and (ii) Pelican Lake; as well as the Southern Alberta oil and gas properties. The division also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

For financial statement reporting purposes, our operating and reportable segments are:

•

Upstream Canada, which includes Cenovus’s development and production of bitumen, crude oil, natural gas and natural gas liquids (“NGLs”), and other related activities in Canada. This includes the Foster Creek and Christina Lake operations which are jointly owned with ConocoPhillips and operated by Cenovus.

•

Downstream Refining, which is focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. The refineries are jointly owned with ConocoPhillips and operated by ConocoPhillips.

•

Corporate and Eliminations, which mainly includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory.

OVERVIEW OF 2009

This past year was highlighted by a number of significant factors that had major influences on our activities and financial results. The most significant factor was the global credit crisis and recession which resulted in lower commodity prices, uncertainty in the financial markets and delayed our creation. However, in September 2009, with some improvement in economic conditions apparent, we were able to arrange a committed Canadian $2.5 billion bank credit facility and successfully raise $3.5 billion in unsecured notes. This allowed us to move forward with the Arrangement, and on November 25, 2009, over 99 percent of the votes cast by EnCana shareholders were in favour of our creation. The global recession also impacted commodity prices which were depressed for most of 2009; however we did benefit from our natural gas and crude oil hedging program, and realized $692 million of after-tax financial hedging gains in 2009.

As a result of the markets uncertainty, we increased focus on cost control and discipline in 2009 through our “10 percent challenge” initiative. Through this focus on cost reduction, we identified opportunities to reduce operating costs and adjust and redirect our capital program. Our reduction of capital expenditures was partly responsible for the nine percent decrease in natural gas production; and although we did reduce spending on our oil projects as well, our average daily production grew 10 percent, with Foster Creek and Christina Lake production increasing 43 percent. Consistent with our long-term strategy to develop our integrated oil business, we continued with our development work at both Foster Creek and Christina Lake, as well as the Coker and Refinery Expansion (“CORE”) project at the Wood River refinery.



Cenovus Energy Inc.		3
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

As part of the creation of Cenovus, EnCana’s Canadian oil and gas partnership was dissolved, resulting in an acceleration of Cenovus’s share of current tax of approximately $400 million in 2009. This current tax is not added tax but are amounts which otherwise would have been paid in 2010 had the dissolution not occurred. This cash tax significantly reduced our Cash Flow for the fourth quarter of 2009. Also, we were part of EnCana for 11 months of the year, and therefore our reported results for 2009 may not be typical of the results that we will achieve in future years as a stand-alone entity.

In addition to the above, the specific financial and operating highlights of 2009 are:

•

160 million barrels, after royalties, of proved bitumen reserves extensions and discoveries mainly due to projects sanctioned in the year; year over year bitumen reserves, after royalties, grew eight percent;

•

Low commodity prices reduced our revenues by 39 percent;

•

Production from our Foster Creek and Christina Lake enhanced oil recovery properties increased 43 percent; Foster Creek production exceeded 100,000 bbls/d (on a 100 percent basis) for the first time in December;

•

Operating Cash Flows from Upstream decreased by $706 million on lower commodity prices;

•

Operating Cash Flows from Downstream Refining operations increased by $551 million;

•

Realized financial hedge gains of $692 million, net of tax; (2008 — loss of $213 million, net of tax);

•

Operating earnings decreased by $317 million;

•

Construction on the CORE project at the Wood River refinery progressed to approximately 71 percent complete at the end of the year and is on schedule and on budget;

•

Acquisition and divestiture activity for the year generated net proceeds of $206 million and added additional bitumen lands at Narrows Lake; and

•

Declared and paid dividends of $151 million ($0.20 per share) in December. The December dividend reflects an amount determined in connection with the Arrangement based on carve-out earnings and cash flow.

OUR BUSINESS ENVIRONMENT

Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and foreign exchange rates to assist in understanding our financial results:


				2009 vs						2008 vs
(Average for the year)	2009			2008			2008			2007			2007
Crude Oil Price ($/bbl)
West Texas Intermediate (WTI)		62.09			-38	%		99.75			38	%		72.41
Western Canadian Select (WCS)		52.43			-34	%		79.70			61	%		49.50
Differential — WTI/WCS		9.66			-52	%		20.05			-12	%		22.91
WCS as % of WTI		84	%					80	%					68	%
Refining Margin 3-2-1 Crack Spread ⁽¹⁾ ($/bbl)
Chicago		8.54			-24	%		11.22			-37	%		17.67
Midwest Combined (“Group 3”)		8.09			-27	%		11.03			-42	%		19.11
Natural Gas Price
AECO (C$/Mcf)		4.19			-48	%		8.13			23	%		6.61
NYMEX ($/MMBtu)		3.99			-56	%		9.04			32	%		6.86
Basis Differential — AECO/NYMEX ($/MMBtu)		0.40			-67	%		1.23			64	%		0.75
Average Foreign Exchange
Average U.S./Canadian Dollar Exchange Rate		0.876			-7	%		0.938			1	%		0.930


(1)		3-2-1 Crack Spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of gasoline and one barrel of ultra low sulphur diesel.

After reaching record highs in July of 2008, the price of WTI decreased over the remainder of the year to a closing price of $44.60 per bbl at December 31, 2008. However, by December 31, 2009, WTI had increased to $79.36 per bbl on signs of an economic recovery and production discipline by OPEC.



Cenovus Energy Inc.		4
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Consistent with the increase in WTI, WCS increased 103 percent from December 31, 2008 to December 31, 2009. During 2009, the average differential between WTI and WCS narrowed to less than $10 per bbl for the year as WCS averaged 84 percent of WTI.

During 2009, U.S. refining crack spreads reflected lower consumer demand, in response to the depressed economy. This reduction in U.S. demand occurred during an overall increase in global refinery capacity. 2009 was the second consecutive annual decline in the consumption of refined products in the United States which resulted in lower prices for refined products and narrowing crack spreads.

Throughout 2009, natural gas prices in North America declined due to a combination of low demand in response to economic conditions and an increase in supply as new prolific shale gas plays began production and associated drilling commitments were completed. The result was above average volumes in storage during 2009 which decreased the price for natural gas. Cold weather during the latter part of 2009, particularly in the eastern United States, helped the AECO price at December 31, 2009 increase from earlier lows of $2.56 per Mcf to $5.25 per Mcf but still remained below last year’s year end level.

Our risk mitigation strategy has reduced our exposure to commodity price volatility through our hedging program. Further information regarding this program can be found in the Risk Management section of this MD&A and the notes to the Consolidated Financial Statements.

ANNUAL FINANCIAL INFORMATION

The Consolidated Financial Statements include the results for the period from January 1 to November 30, 2009 (prior to the start of our independent operations on December 1, 2009) in addition to the results for the period from December 1 to December 31, 2009. The historical consolidated financial information prior to December 1, 2009 has been derived from the accounting records of EnCana using the historical results of operations and historical basis of assets and liabilities of the businesses subsequently transferred to Cenovus on a carve-out accounting basis. Further details are provided in the notes to the Consolidated Financial Statements.

SELECTED ANNUAL CONSOLIDATED FINANCIAL RESULTS


			2009 vs					2008 vs
($ millions, except per share amounts)	2009		2008			2008		2007			2007
Revenues, Net of Royalties	$	10,140		-39	%	$	16,559		24	%	$	13,406
Operating Cash Flow ⁽¹⁾		3,695		-4	%		3,850		-11	%		4,344
Cash Flow ⁽¹⁾		2,472		-20	%		3,088		-13	%		3,536
- per share — diluted ⁽²⁾		3.29					4.11					4.62
Operating Earnings ⁽¹⁾		1,312		-19	%		1,629		-10	%		1,802
- per share — diluted ⁽²⁾		1.74					2.17					2.36
Net Earnings		648		-73	%		2,368		69	%		1,404
- per share — basic ⁽²⁾		0.86					3.16					1.87
- per share — diluted ⁽²⁾		0.86					3.15					1.84

Total Assets		20,552		11	%		18,466		-12	%		20,987
Total Long-Term Debt		3,493		15	%		3,036		-18	%		3,690
Other Long-Term Obligations		6,043		1	%		5,968		-7	%		6,437

Capital Expenditures		1,892		-8	%		2,046		39	%		1,475
Free Cash Flow ⁽¹⁾		580		-44	%		1,042		-49	%		2,061
Cash Dividends ⁽³⁾		151					—					—


(1)		Non-GAAP measures which are defined within this MD&A.

(2)		Any per share amounts prior to December 1, 2009 have been calculated using EnCana’s common share balances based on the terms of the Arrangement where EnCana shareholders received one common share of the new EnCana.

(3)		We declared and paid a dividend of $0.20 per share in December 2009. The December dividend reflects an amount determined in connection with the Arrangement based on carve-out earnings and cash flow.



Cenovus Energy Inc.		5
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

REVENUE VARIANCE


($ millions)
2008 Revenue, Net of Royalties		$	16,559
Upstream	Price		(2,138	)
	Realized hedging		1,328
	Volume		(15	)
	Other ⁽¹⁾		(549	)
Downstream			(3,731	)
Corporate	Unrealized hedging		(1,366	)
	Other		52

2009 Revenue, Net of Royalties		$	10,140


(1)		Revenue dollars reported include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and selling expense.

Total Revenues, Net of Royalties decreased $6,419 million in 2009 compared to 2008 primarily as a result of lower average commodity prices, consistent with decreased benchmark prices for 2009.

OPERATING CASH FLOW


($ millions)	2009		2008			2007
Crude Oil and NGLs
Foster Creek and Christina Lake	$	596	$	421		$	213
Canadian Plains		941		1,508			946
Natural Gas		1,798		2,099			2,049
Other Upstream Operations		50		63			62

		3,385		4,091			3,270
Downstream		310		(241	)		1,074

Operating Cash Flow	$	3,695	$	3,850		$	4,344

Operating Cash Flow is a non-GAAP measure defined as Revenue, Net of Royalties less production and mineral taxes, transportation and selling, operating and purchased product expenses and is used to provide a consistent measure of the cash generating performance of our assets and improves the comparability of our underlying financial performance between periods.

In total, Operating Cash Flow from our Upstream and Downstream segments decreased by $155 million. Detail of the components that explain changes to Operating Cash Flow from 2008 can be found in the Divisional Results section of this MD&A.

CASH FLOW

Cash Flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital. Cash Flow is commonly used in the oil and gas industry to assist in measuring the ability to finance capital programs and meet financial obligations.


($ millions)	2009			2008			2007
Cash From Operating Activities	$	3,496		$	2,687		$	3,014
(Add back) deduct:
Net change in other assets and liabilities		(23	)		(89	)		(48	)
Net change in non-cash working capital		1,047			(312	)		(474	)

Cash Flow	$	2,472		$	3,088		$	3,536



Cenovus Energy Inc.		6
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Our Cash Flow decreased to $2,472 million in 2009, a decrease of $616 million from 2008 ($3,088 million). The decrease was the result of:

•

Decrease in the average natural gas price, excluding financial hedging, of $4.16 per Mcf or 54 percent from 2008;

•

Decrease in the average liquids selling price, excluding financial hedging, of $23.13 per bbl, or 31 percent, from 2008;

•

Current tax increased $513 million primarily due to accelerated income tax as a result of the dissolution of a partnership as part of the Arrangement; and

•

Decline of nine percent in our production of natural gas.

The decreases in our 2009 Cash Flow were offset by:

•

Realized financial hedging gains of $692 million, after tax, compared to realized hedging losses of $213 million, after tax, in 2008;

•

An improvement in our operating cash flow from downstream operations of $551 million;

•

A decrease in our transportation and selling and operating expenses of $360 million; and

•

10 percent increase in our crude oil and NGLs production volumes compared to 2008.

Our Cash Flow in 2008 of $3,088 million was lower than 2007 Cash Flow of $3,536 million by $448 million, primarily due to:

•

Operating cash flows from downstream operations decreased $1,315 million primarily due to weaker refining margins and higher purchased product costs;

•

Realized financial crude oil, natural gas and other commodity hedging losses of $213 million after-tax in 2008, compared to gains of $97 million after-tax in 2007;

•

Natural gas production volumes in 2008 decreased six percent compared to 2007; and

•

Increases in transportation and selling, operating, interest and general and administrative expenses.

The decreases in our 2008 Cash Flow were offset by:

•

Higher average natural gas prices, excluding financial hedges, of $7.76 per Mcf in 2008 compared to $6.08 per Mcf in 2007; and

•

Higher average liquids prices, excluding financial hedges of $74.00 per bbl in 2008 compared to $46.69 per bbl in 2007.

OPERATING EARNINGS


($ millions)	2009			2008		2007
Net Earnings, as reported	$	648		$	2,368	$	1,404
Add back (losses) and deduct gains:
Unrealized mark-to-market accounting gain (loss), after-tax ⁽¹⁾		(473	)		519		(244	)
Non-operating foreign exchange gain (loss), after-tax ⁽²⁾		(191	)		220		(301	)
Future tax recovery due to tax rate reductions		—			—		147

Operating Earnings	$	1,312		$	1,629	$	1,802


(1)		The unrealized mark-to-market accounting gains (losses), after-tax includes the reversal of unrealized gains (losses) recognized in prior periods. The realized gains (losses), after-tax represents the recording of the final settlement of hedge positions.

(2)		After-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, after-tax realized foreign exchange gains (losses) on settlement of intercompany transactions and future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt.

Operating Earnings is a non-GAAP measure defined as Net Earnings excluding non-operating items including the after-tax effect of unrealized mark-to-market accounting gains (losses) on derivative instruments, after-tax gains (losses) on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions, future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates.



Cenovus Energy Inc.		7
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

We believe that these non-operating items reduce the comparability of our underlying financial performance between periods. The above reconciliation of Operating Earnings has been prepared to provide information that is more comparable between periods. The items identified above that affected our Cash Flow and below that affected our Net Earnings also impacted our Operating Earnings.

NET EARNINGS

Net Earnings in 2009 of $648 million were $1,720 million lower compared to 2008. The items identified above that affected our 2009 Cash Flow also impacted Net Earnings. Other significant factors that reduced our 2009 Net Earnings included an unrealized mark-to-market loss of $667 million, compared to a $734 million gain in 2008 and unrealized foreign exchange loss of $313 million in 2009 compared to a gain in 2008 of $259 million. These reductions to Net Earnings and the increased current tax, which impacted Cash Flow, were offset by a recovery of future income tax in 2009 of $551 million, compared to a future income tax expense of $385 million in 2008.

Our Net Earnings in 2008 were $2,368 million, which were $964 million higher than Net Earnings of $1,404 million in 2007. The items identified above that affected our 2008 Cash Flow also impacted Net Earnings. Other significant factors that increased our 2008 Net Earnings included an unrealized mark-to-market gain, after-tax, of $519 million, compared to a $244 million loss in 2007, non-operating foreign exchange gains of $220 million, after-tax, in 2008 compared to losses of $301 million after-tax in 2007 as well as a $108 million decrease in depreciation, depletion and amortization.

As a means of managing the volatility of commodity prices, we enter into various financial instrument agreements. Changes in the mark-to-market gain or loss on these agreements affect our Net Earnings and are the result of volatility in the forward commodity prices and changes in the balance of unsettled contracts. Our 2009 and 2008 Net Earnings benefitted overall from this program, while in 2007, we reported a reduction in Net Earnings from our hedging program. The following information has been provided in order to provide information that is more comparable between periods:


($ millions)	2009			2008			2007
Unrealized Mark-to-Market Gains (Losses), after-tax(1)	$	(473	)	$	519		$	(244	)
Realized Hedging Gains (Losses), after-tax (2)		692			(213	)		97

Hedging Impacts on Net Earnings	$	219		$	306		$	(147	)


(1)		Included in Corporate financial results. Further detail on unrealized mark-to-market gains (losses) can be found in the Corporate and Eliminations section of this MD&A.

(2)		Included in Divisional financial results.

NET CAPITAL INVESTMENT


($ millions)	2009			2008			2007
Integrated Oil — Upstream	$	476		$	644		$	450
Canadian Plains		478			872			795
Downstream Refining		907			478			220
Other		31			52			10

Capital Investment		1,892			2,046			1,475
Acquisitions		3			—			14
Divestitures		(209	)		(47	)		—

Net Capital Investment	$	1,686		$	1,999		$	1,489

Capital investment in 2009 was primarily focused on the continued development of our EOR properties (Foster Creek, Christina Lake, Pelican Lake and Weyburn) and the expansion of our downstream heavy oil refining capacity. During 2009, part of the reduction in our capital investment reflected our internal “10 percent challenge”, as we scrutinized our spending in an effort to reduce costs. Capital investment for each of 2009, 2008 and 2007 was funded by Cash Flow. Further information regarding our capital investment can be found in the Divisional Results section of this MD&A.



Cenovus Energy Inc.		8
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Acquisitions and Divestitures

In 2009, acquisition and divestiture activity resulted in net proceeds of $206 million from various divestitures, including the sale of the Senlac heavy oil assets, a farm-out transaction and one minor acquisition.

Our acquisitions and divestitures in 2009 also included a property swap under the terms of which we acquired strategic bitumen lands at Narrows Lake in exchange for certain non-core lands.

FREE CASH FLOW

In order to determine the funds available for financing and investing activities, including dividend payments, we use a non-GAAP measure of Free Cash Flow, which is defined as Cash Flow in excess of Capital Investment, excluding acquisitions and divestitures. Cash Flow is a non-GAAP measure and is defined under the Cash Flow section of this MD&A.

In 2009, our Free Cash Flow was $580 million, which was $462 million lower than our Free Cash Flow of $1,042 million in 2008 (2007 — $2,061 million) primarily due to lower cash flow, partially offset by less capital investment during the year. Additional explanations for the decrease in total Cash Flow and Capital Investment are discussed under the Cash Flow, Net Capital Investment and Divisional Results sections of this MD&A.


($ millions)	2009		2008		2007
Cash Flow	$	2,472	$	3,088	$	3,536
Capital Investment		1,892		2,046		1,475

Free Cash Flow	$	580	$	1,042	$	2,061

FOREIGN EXCHANGE

As disclosed in the Business Environment section of this MD&A, the average U.S./Canadian dollar exchange rate was lower in 2009 than both 2008 and 2007. The table below summarizes the impact of the lower foreign exchange rate on reported amounts when compared to the prior years.


	2009			2008			2007
Average U.S./Canadian Dollar Exchange Rate	$	0.876		$	0.938		$	0.930
Dollar Change from prior year	$	(0.062	)	$	0.008		$	0.048
Percentage change from prior year		-7	%		1	%		5	%
($ millions)
Increase (decrease) in:
Capital Investment	$	(82	)	$	(12	)	$	80
Operating Expense		(46	)		7			40
Administrative Expense		(9	)		1			6
DD&A Expense		(82	)		13			73

The U.S. to Canadian dollar exchange rate strengthened from a December 31, 2008 spot rate of $0.824 to a December 31, 2009 spot rate of $0.955. The $0.131 increase resulted in a Foreign Currency Translation Adjustment of $2.0 billion, net of tax for 2009 which increased our Comprehensive Income. As the U.S. to Canadian dollar exchange rate weakened from a rate of $1.007 at December 31, 2007 to $0.824 at December 31, 2008 our Foreign Currency Translation Adjustment for 2008 reduced our Comprehensive Income by $2.2 billion, net of tax.



Cenovus Energy Inc.		9
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

RESULTS OF OPERATIONS

Crude Oil and NGLs Production Volumes


			2009 vs					2008 vs
	2009		2008			2008		2007			2007
Crude Oil (bbls/d)
Foster Creek		36,654		41	%		25,947		7	%		24,262
Christina Lake		6,527		54	%		4,236		66	%		2,552
Weyburn		14,948		7	%		14,031		-5	%		14,771
Pelican Lake		20,105		-9	%		21,975		-5	%		23,253
Southern Alberta		22,406		-7	%		24,153		-10	%		26,776
Integrated Oil — Other		2,553		-6	%		2,729		2	%		2,688
Canadian Plains — Other		5,405		-10	%		5,998		-2	%		6,139
NGLs (bbls/d)		1,186		—	%		1,181		-6	%		1,260

		109,784		10	%		100,250		-1	%		101,701

Production volumes at Foster Creek and Christina Lake increased in 2009 as a result of the commissioning and ramp up of new expansion phases at each property, slightly offset by higher royalty rates as a result of the new Alberta royalty framework (effective January 1, 2009), which reduced the production volumes. Weyburn production increased from 2008 to 2009 as a result of well optimizations and lower royalties. The decrease in production at Pelican Lake for 2009 was a result of natural production declines and a scheduled facility turnaround partially offset by fewer operational issues at the facility. Crude oil production from Southern Alberta decreased in 2009 compared to 2008 due to expected natural declines partially offset by lower royalty rates and production from new wells.

Natural Gas Production Volumes


			2009 vs					2008 vs
	2009		2008			2008		2007			2007
Natural Gas (MMcf/d)
Southern Alberta		739		-8	%		800		-4	%		832
Canadian Plains — Other		36		-14	%		42		-2	%		43
Integrated Oil — Other		49		-22	%		63		-31	%		91

		824		-9	%		905		-6	%		966

The decline in Southern Alberta natural gas production in 2009 compared to 2008 was the result of expected natural production declines and capacity restrictions in response to the lower commodity price. These production decreases were partially offset by a slight reduction in the royalty rates as a result of declining prices.

Operating Netbacks


	2009				2008						2007
			Natural					Natural						Natural
	Liquids		Gas		Liquids			Gas			Liquids			Gas
	($/bbl)		($/Mcf)		($/bbl)			($/Mcf)			($/bbl)			($/Mcf)
Price	$	50.87	$	3.60	$	74.00		$	7.76		$	46.69		$	6.08
Expenses
Production and mineral taxes		0.62		0.04		1.08			0.11			0.76			0.10
Transportation and selling		1.55		0.14		1.71			0.24			1.72			0.27
Operating		10.41		0.76		11.59			0.84			10.27			0.74

Netback excluding Realized Financial Hedging		38.29		2.66		59.62			6.57			33.94			4.97
Realized Financial Hedging Gain (Loss)		0.98		3.22		(6.07	)		(0.30	)		(3.40	)		0.75

Netback including Realized Financial Hedging	$	39.27	$	5.88	$	53.55		$	6.27		$	30.54		$	5.72



Cenovus Energy Inc.		10
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Our average netback for both liquids and natural gas (excluding realized financial hedging) was lower in 2009 primarily as a result of lower average prices for the year, consistent with the reduction in benchmark prices.

As part of ongoing efforts to maintain financial resilience and flexibility, we reduced our pricing risk through a commodity price hedging program. In 2009, our hedging program added $0.98 per bbl of liquids and $3.22 per Mcf of natural gas. Further information regarding this program can be found in the Risk Management section of this MD&A and the notes to the Consolidated Financial Statements.

DIVISIONAL RESULTS

Our Upstream Canada segment includes the upstream activities of the Integrated Oil Division and the Canadian Plains Division. Our Downstream Refining segment includes the Downstream Refining business of the Integrated Oil Division.

INTEGRATED OIL DIVISION

We are a 50 percent partner in an integrated North American oil business with ConocoPhillips that consists of an upstream and a downstream entity. The upstream entity includes the Foster Creek and Christina Lake oil properties in northeast Alberta, while the downstream entity includes the Wood River and Borger refineries located in Illinois and Texas, USA, respectively.

FOSTER CREEK AND CHRISTINA LAKE

Financial Results


($ millions)	2009		2008			2007
Revenues, Net of Royalties and excluding hedging	$	1,165	$	1,184		$	781
Realized Financial Hedging Gain (Loss)		37		(67	)		(43	)
Expenses
Transportation and selling		430		526			366
Operating		176		170			159

Operating Cash Flow	$	596	$	421		$	213

Production Volumes


			2009 vs					2008 vs
	2009		2008			2008		2007			2007
Heavy Crude Oil (bbls/d)
Foster Creek		36,654		41	%		25,947		7	%		24,262
Christina Lake		6,527		54	%		4,236		66	%		2,552

		43,181		43	%		30,183		13	%		26,814

Revenue Variance


	2008 Revenues		Revenue								2009 Revenues
	Net of		Variances in:								Net of
($ millions)	Royalties		Price⁽¹⁾			Volume		Other⁽²⁾			Royalties
Foster Creek and Christina Lake	$	1,117	$	(94	)	$	286	$	(107	)	$	1,202


(1)		Includes the impact of realized financial hedging.

(2)		Revenue dollars reported include the value of condensate sold as bitumen blend. Condensate costs are recorded in transportation and selling expense.



Cenovus Energy Inc.		11
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Revenues, net of royalties, excluding realized financial hedging, decreased $19 million in 2009 compared to 2008 as a result of lower average crude oil prices offset by an increase in crude oil production of 43 percent. During 2009, financial hedging activities realized a gain of $37 million ($2.35 per bbl) compared to a loss of $67 million ($6.11 per bbl) in 2008 (2007 — loss of $43 million; $3.88 per bbl).

Our average crude oil sales price decreased 20 percent to $49.71 per bbl in 2009 from $62.44 per bbl in 2008 primarily due to a 38 percent decrease in average WTI prices over the year offset somewhat by the narrowing of the WCS differential.

Production at Foster Creek increased 41 percent in 2009 compared to 2008 as a result of production from the phase C and D/E expansions, as well as additional production from wedge wells, offset slightly by higher royalty rates. Production from phase C reached capacity of 60,000 bbls/d in the third quarter of 2008. Production from the phase D/E expansion commenced late in the first quarter of 2009 and ramped up throughout the year.

Production at Christina Lake increased 54 percent in 2009 compared to 2008 as a result of higher production from the phase B expansion which commenced production in the second quarter of 2008 slightly offset by higher royalty rates in 2009.

Transportation and selling costs are comprised mostly of condensate costs, as blending condensate with bitumen enables the product to be transported. During 2009, condensate volumes increased due to the higher production noted above, offset by a 45 percent decrease in the average price of condensate used for blending. This resulted in a reduction of transportation and selling costs to $430 million in 2009 from $526 million in 2008 (2007 — $366 million).

Operating costs in 2009 increased slightly to $176 million compared to $170 million in 2008 due to the significant increase in volumes combined with additional repairs and maintenance and a scheduled turnaround at Christina Lake in the fall of 2009. The increase in operating costs was offset by lower fuel costs due to declining natural gas prices as well as higher volumes of Athabasca natural gas production being used internally at Foster Creek, requiring less fuel to be purchased in the market.

DOWNSTREAM REFINING

Financial Results


($ millions)	2009		2008			2007
Revenues	$	5,280	$	9,011		$	7,315
Expenses
Operating		453		492			428
Purchased product		4,517		8,760			5,813

Operating Cash Flow	$	310	$	(241	)		1,074

Refinery Operations ⁽¹⁾


	2009		2008		2007
Crude oil capacity (Mbbls/d)		452		452		452
Crude oil runs (Mbbls/d)		394		423		432
Crude utilization (%)		87		93		96
Refined products (Mbbls/d)		417		448		457


(1)		Represents 100% of the Wood River and Borger refinery operations.

On a 100 percent basis, our refineries have a current capacity of approximately 452,000 bbls/d of crude oil and 45,000 bbls/d of NGLs, as well as processing capability to refine approximately 145,000 bbls/d of heavy crude oil (approximately 70,000 bbls/d of bitumen equivalent). Upon completion of the Wood River CORE project in 2011 we expect to be able to refine approximately 275,000 bbls/d (on a 100 percent basis) of heavy crude oil (approximately 150,000 bbls/d of bitumen equivalent) primarily into motor fuels.



Cenovus Energy Inc.		12
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

During 2009, our refineries operated at an average of 87 percent of their capacity compared to 93 percent in 2008. Utilization was lower in 2009 primarily due to refinery optimization based on weakened market crack spreads, increased number of turnarounds at Wood River to advance the CORE project and unplanned maintenance at both refineries.

Revenues have decreased 41 percent and purchased product has decreased 48 percent in 2009, consistent with the decrease in crude oil prices. Purchased product, consisting mainly of crude oil, represented 91 percent of total expenses in 2009 compared to 95 percent in 2008. Operating costs, consisting mainly of labour, utilities and supplies, decreased eight percent in 2009 due to lower prices for electricity and fuel gas consumed at the refineries.

Operating Cash Flow for 2009 was $551 million higher than 2008 mainly due to lower purchased product costs more than offsetting lower refined product sales. The increase was partially offset by lower refinery utilization.

INTEGRATED OIL DIVISION — OTHER PROPERTIES

The Integrated Oil Division also manages our 100 percent owned natural gas operations in Athabasca. For 2009, natural gas production volumes from Athabasca decreased to 49 MMcf/d (2008 — 63 MMcf/d; 2007 — 91 MMcf/d) primarily as a result of increased usage of natural gas as a source of fuel for the Foster Creek operations as well as natural declines.

In November 2009, we sold our Senlac heavy oil assets for proceeds of approximately $83 million. Prior to the divestiture, Senlac production was 2,553 bbls/d in 2009 compared to 2,729 bbls/d in 2008 (2007 — 2,688 bbls/d).

INTEGRATED OIL DIVISION — CAPITAL INVESTMENT


($ millions)	2009		2008		2007
Upstream	$	476	$	644	$	450
Downstream Refining		907		478		220

Total Integrated Oil Division	$	1,383	$	1,122	$	670

Our Upstream capital investment in 2009 was primarily focused on the continued development of the next phases of the Foster Creek and Christina Lake properties. Capital investment was lower in 2009 because of lower drilling costs as we drilled fewer stratigraphic test wells at Foster Creek, Christina Lake and Borealis, combined with a lower foreign exchange rate. Our current plan is to increase production capacity at Foster Creek and Christina Lake to approximately 218,000 bbls/d of bitumen with the completion of Christina Lake phase C in 2011 and phase D in 2013. We have chosen to accelerate completion of Christina Lake phase D which we expect will advance start up by approximately six months.

Our Downstream Refining capital investment in 2009 continued to focus on the CORE project at the Wood River refinery, as we significantly increased capital expenditures to $907 million in 2009 from $478 million in 2008 (2007 — $220 million). The CORE project is expected to cost approximately $1.8 billion (net to Cenovus) and is anticipated to be completed and in operation in 2011. The expansion is expected to increase crude oil refining capacity by 50,000 bbls/d to 356,000 bbls/d and more than double heavy crude oil refining capacity at Wood River to 240,000 bbls/d. At December 31, 2009, construction on the CORE project was approximately 71 percent complete and continued to be on schedule and within budgeted costs.



Cenovus Energy Inc.		13
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

CANADIAN PLAINS DIVISION

Crude Oil and NGLs

Financial Results


($ millions)	2009		2008			2007
Revenues, Net of Royalties and excluding hedging	$	1,371	$	2,256		$	1,540
Realized Financial Hedging Gain (Loss)		2		(150	)		(87	)
Expenses
Production and mineral taxes		24		38			29
Transportation and selling		179		321			263
Operating		229		239			215

Operating Cash Flow	$	941	$	1,508		$	946

Production Volumes


			2009 vs					2008 vs
	2009		2008			2008		2007			2007
Heavy Oil (bbls/d)
Pelican Lake		20,105		-9	%		21,975		-5	%		23,253
Southern Alberta		12,038		-8	%		13,054		-16	%		15,530
Light and Medium Oil (bbls/d)
Weyburn		14,948		7	%		14,031		-5	%		14,771
Southern Alberta		10,368		-7	%		11,099		-1	%		11,246
Other		5,405		-10	%		5,998		-2	%		6,139
NGLs (bbls/d)		1,186		0	%		1,181		-6	%		1,260

Revenue Variance


	2008 Revenues		Revenue									2009 Revenues
	Net of		Variances in:									Net of
($ millions)	Royalties		Price⁽¹⁾			Volume			Other⁽²⁾			Royalties
Canadian Plains	$	2,106	$	(501	)	$	(104	)	$	(128	)	$	1,373


(1)		Includes the impact of realized financial hedging.

(2)		Revenue dollars reported include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and selling expense.

Crude oil and NGL revenues, net of royalties, excluding realized financial hedging, decreased $885 million in 2009 compared to 2008 due to lower commodity prices and production volumes.

The average crude oil sales price, excluding realized hedging, decreased 35 percent to $51.80 per bbl in 2009 from $79.09 per bbl in 2008, consistent with changes in the benchmark WTI and WCS crude oil prices. During 2009, crude oil and NGLs realized financial hedging gains were $2 million ($0.10 per bbl) compared to losses of $150 million ($6.02 per bbl) in 2008 (2007 — loss of $87 million; $3.32 per bbl).

Production volumes at Weyburn were seven percent higher in 2009 compared to 2008 mainly due to well optimizations and lower royalty rates partially offset by natural declines. At Pelican Lake, volumes were nine percent lower in 2009 compared to 2008 mainly due to natural declines and a scheduled facility turnaround partially offset by less facility downtime. Southern Alberta oil production was down eight percent from 2008 primarily due to expected natural declines partially offset by production from new wells.

Production and mineral taxes of $24 million in 2009 decreased from $38 million in 2008 (2007 — $29 million) consistent with lower crude oil prices.



Cenovus Energy Inc.		14
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Transportation and selling costs of $179 million in 2009 decreased from $321 million in 2008 (2007 - $263 million) due to a 39 percent decrease in the average price and a nine percent decrease in volume of condensate used for blending with heavy oil.

Operating costs decreased to $229 million in 2009 from $239 million in 2008 (2007 — $215 million) due to a lower foreign exchange rate and lower workover activity partially offset by higher chemical usage and electricity costs. NGLs are a byproduct obtained through the production of natural gas and therefore operating costs associated with the production of NGLs are included with natural gas.

Natural Gas

Financial Results


($ millions)	2009		2008			2007
Revenues, Net of Royalties and excluding hedging	$	1,022	$	2,392		$	1,946
Realized Financial Hedging Gain (Loss)		880		(91	)		240
Expenses
Production and mineral taxes		13		36			34
Transportation and selling		39		71			82
Operating		210		241			221

Operating Cash Flow	$	1,640	$	1,953		$	1,849

Production Volumes


			2009 vs					2008 vs
	2009		2008			2008		2007			2007
Natural Gas (MMcf/d)
Southern Alberta		739		-8	%		800		-4	%		832
Other		36		-14	%		42		-2	%		43

		775					842					875

Revenue Variance


	2008 Revenues		Revenue						2009 Revenues
	Net of		Variances in:						Net of
($ millions)	Royalties		Price⁽¹⁾			Volume			Royalties
Canadian Plains	$	2,301	$	(210	)	$	(189	)	$	1,902


(1)		Includes the impact of realized financial hedging.

Natural gas revenues, net of royalties, excluding realized financial hedging, decreased $1,370 million in 2009 compared to 2008, primarily due to lower natural gas prices as well as lower production volumes. Average natural gas prices, excluding the impact of financial hedges, decreased to $3.62 per Mcf in 2009 from $7.77 per Mcf in 2008 consistent with the reduction in the benchmark AECO price. In 2009, we realized a financial hedging gain of $880 million ($3.11 per Mcf) compared to a loss of $91 million ($0.29 per Mcf) in 2008 (2007 — gain of $240 million; $0.75 per Mcf).

Production volumes for Southern Alberta decreased eight percent in 2009 compared to 2008 due to expected natural declines and lower drilling and tie-in activity in response to lower commodity prices partially offset by lower royalty rates.

Production and mineral taxes of $13 million in 2009 decreased from $36 million in 2008 (2007 — $34 million) primarily as a result of lower natural gas prices and lower production volumes.

Transportation and selling costs of $39 million in 2009 decreased from $71 million in 2008 (2007 - $82 million) due to lower volumes being shipped to eastern Canada and the eastern United States and the lower foreign exchange rate.



Cenovus Energy Inc.		15
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Operating expenses in 2009 decreased to $210 million from $241 million in 2008 (2007 — $221 million) mostly as a result of the lower foreign exchange rate combined with a lower level of repair, maintenance and workover activity.

Canadian Plains — Other

Financial Results


($ millions)	2009		2008		2007
Revenues, Net of Royalties and excluding hedging	$	868	$	1,137	$	1,824
Expenses
Transportation and selling		—		—		10
Operating		18		22		23
Purchased product		832		1,101		1,751

Operating Cash Flow	$	18	$	14	$	40

The Canadian Plains Division markets all of our crude oil and natural gas, including third party purchases and sales of product, in order to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification. The decrease in both revenues and purchased product expenses for 2009 compared to 2008 is consistent with decreased average market prices during 2009. Canadian Plains — Other also includes a small amount of third party processing fee income.

Capital Investment

Canadian Plains capital investment in 2009 was $478 million (2008 — $872 million; 2007 — $795 million). The $394 million decrease from 2008 was primarily the result of management’s decision to reduce capital investment in response to lower commodity prices in 2009. The reduction came primarily from lower natural gas drilling, completion and tie-in activity, as well as the lower foreign exchange rate, and lower land acquisition expenditures, partially offset by higher heavy crude oil drilling activity. Canadian Plains drilled 614 net wells in 2009 compared to 1,476 net wells in 2008 (2007 — 2,264 net wells).

CORPORATE AND ELIMINATIONS

Financial Results


($ millions)	2009			2008			2007
Revenues	$	(738	)	$	576		$	(437	)
Expenses
Operating		30			(11	)		(2	)
Purchased product		(99	)		(151	)		(88	)
Depreciation, depletion and amortization		50			23			45
General and administrative		188			167			145
Interest, net		218			218			187
Accretion of asset retirement obligation		39			39			28
Foreign exchange (gain) loss, net		290			(250	)		380
(Gain) loss on divestitures		(2	)		3			4

Segment Income (Loss)	$	(1,452	)	$	538		$	(1,136	)

The Corporate and Eliminations segment includes revenues that represent the unrealized mark-to-market gains or losses related to derivative financial instruments used to mitigate fluctuations in commodity prices. The segment also includes inter-segment eliminations that relate to transactions that have been recorded at transfer prices based on current market prices as well as unrealized intersegment profits in inventory. Operating expenses primarily relate to mark-to-market gains and losses on long-term power purchase contracts and downstream crude oil supply positions. Depreciation, Depletion and Amortization (“DD&A”) includes provisions in respect of corporate assets, such as computer equipment, office furniture and leasehold improvements.



Cenovus Energy Inc.		16
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

General and administrative expenses increased $21 million in 2009 compared to 2008 primarily due to higher long-term compensation costs as a result of the increased share price and expenses related to the creation of Cenovus offset by a lower foreign exchange rate.

Interest expense in 2009 was $218 million, unchanged from 2008 interest expense, of $218 million (2007 — $187 million) primarily as a result of our average level of debt outstanding and interest rates being consistent between 2008 and 2009. Our weighted average interest rate on outstanding debt at December 31, 2009 was 5.8 percent, compared to 5.5 percent in 2008.

We reported a foreign exchange loss of $290 million in 2009 compared to a gain of $250 million in 2008 (2007 — loss of $380 million), the majority of which was unrealized. We are exposed to foreign exchange gains and losses primarily on our U.S. dollar partnership contribution receivable and our U.S. dollar denominated debt issued from Canada. The strengthening of the Canadian dollar during 2009 led to unrealized losses on our partnership contribution receivable, which was partially offset by unrealized gains on our U.S. dollar debt. We also reported an unrealized foreign exchange loss of $107 million during the year relating to the translation of our U.S. dollar risk management assets and liabilities, compared to an unrealized gain of $2 million in 2008 (2007 — unrealized loss of $34 million). The loss incurred in 2009 was also primarily due to the strengthening of the Canadian dollar during the year.

Depreciation, Depletion and Amortization

In 2009, DD&A was $1,343 million compared to $1,318 million in 2008 (2007 — $1,426 million). We use full cost accounting for our upstream oil and gas activities and calculate DD&A on a country-by-country cost centre basis. Upstream DD&A of $1,101 million in 2009 was consistent with 2008 DD&A of $1,107 million (2007 — $1,222 million) as a result of a higher DD&A rate offset by a lower foreign exchange rate and slightly lower production volumes. In 2009, DD&A on our Downstream Refining assets was $192 million, which was consistent with 2008 DD&A of $188 million (2007 — $159 million). DD&A in the Corporate and Eliminations segment was $50 million for 2009 compared to $23 million for 2008 (2007 — $45 million).

Income Tax

Total income tax expense in 2009 was $302 million, which was $423 million lower than 2008 mainly due to lower earnings before income tax. Current income tax expense in 2009 was $853 million compared to $340 million in 2008, with the increase largely being attributable to the acceleration of income tax arising from the dissolution of EnCana’s Canadian oil and gas partnership in connection with the Arrangement, as well as the realization of significant hedging gains in 2009. This accelerated current tax was offset by a future tax recovery for the tax that would have been paid in 2010. Current tax expense for the three years is primarily an allocation of EnCana’s income tax liability on a carve-out accounting basis our portion of which was settled as part of the Arrangement and therefore we do not have any income tax payable at December 31, 2009.

In 2009, we had a future income tax recovery of $551 million compared to an expense of $385 million in 2008. The significant net recovery in 2009 is due to the reversal of the future tax which offsets the accelerated current income tax on partnership income, as noted above, as well as 2008 unrealized mark-to-market hedging gains.

In 2009, our effective tax rate was 31.8 percent compared to 23.4 percent in 2008. The increase is primarily due to the provision of future income tax on unrealized foreign exchange gains as well as a variety of rate differences.



Cenovus Energy Inc.		17
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Additional information regarding our effective tax rate can be found in the notes to the Consolidated Financial Statements. Our effective tax rate in any year is a function of the relationship between total tax expense and the amount of earnings before income taxes for the year. The effective tax rate differs from the statutory tax rate as it takes into consideration permanent differences, adjustments for changes in tax rates and other tax legislation, variation in the estimate of reserves and the differences between the provision and the actual amounts subsequently reported on the tax returns. Permanent differences include:

•		The non-taxable portion of Canadian capital gains and losses;

•		International financing; and

•		Foreign exchange (gains) losses not included in Net Earnings.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As a result, there are usually some tax matters under review. We believe that our provision for taxes is adequate.

Summary of Unrealized Mark-to-Market Gains (Losses)

The volatility of commodity prices has a significant impact on our Net Earnings, and as a means of managing this volatility, we enter into various financial instrument agreements. The financial instrument agreements were recorded at the date of the financial statements based on mark-to-market accounting. Changes in the mark-to-market gain or loss reflected in corporate revenues are the result of volatility between periods in the forward commodity prices and changes in the balance of unsettled contracts. The table below provides a summary of the unrealized mark-to-market gains and losses recognized for each year. Additional information regarding financial instrument agreements can be found in the notes to the Consolidated Financial Statements.


($ millions)	2009			2008			2007
Revenues
Crude Oil	$	(98	)	$	212		$	(161	)
Natural Gas		(541	)		515			(188	)

		(639	)		727			(349	)
Expenses		28			(7	)		(1	)

		(667	)		734			(348	)
Income Tax Expense (Recovery)		(194	)		215			(104	)

Unrealized Mark-to-Market Gains (Losses), after tax	$	(473	)	$	519		$	(244	)



Cenovus Energy Inc.		18
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

QUARTERLY FINANCIAL DATA


($ millions, except per share	2009									2008
amounts)	Q4			Q3		Q2		Q1		Q4			Q3		Q2		Q1
Revenues, Net of Royalties	$	2,835		$	2,714	$	2,429	$	2,162	$	3,207		$	5,533	$	4,381	$	3,438
Operating Cash Flow ⁽¹⁾		909			1,032		1,008		746		101			1,133		1,518		1,098
Cash Flow ⁽¹⁾		225			841		811		595		(174	)		1,123		1,228		911
- per share — diluted ⁽²⁾		0.30			1.12		1.08		0.79		(0.23	)		1.50		1.63		1.21
Operating Earnings ⁽¹⁾		152			382		447		331		(123	)		611		710		431
- per share — diluted ⁽²⁾		0.20			0.51		0.59		0.44		(0.16	)		0.81		0.95		0.57
Net Earnings		24			63		149		412		380			1,299		522		167
- per share — basic ⁽²⁾		0.03			0.08		0.20		0.55		0.51			1.73		0.70		0.22
- per share — diluted ⁽²⁾		0.03			0.08		0.20		0.55		0.51			1.73		0.70		0.22
Capital expenditures		481			471		416		524		626			469		435		516
Free Cash Flow ⁽¹⁾		(256	)		370		395		71		(800	)		654		793		395
Cash Dividends ⁽³⁾		151			—		—		—		—			—		—		—


(1)		Non-GAAP measures which are defined in this MD&A.

(2)		Any per share amounts prior to December 1, 2009 have been calculated using EnCana’s common share balances based on the terms of the Arrangement where EnCana shareholders received one common share of Cenovus and one common share of the new EnCana.

(3)		We declared and paid a dividend of $0.20 per share in December 2009. The December dividend reflects an amount determined in connection with the Arrangement based on carve-out earnings and cash flow.

Our Cash Flow in the fourth quarter of 2009 increased $399 million compared to the fourth quarter of 2008. The main drivers for the increase in Cash Flow were:

•

The improvement of downstream operating cash flow in 2009 was the result of the fourth quarter in 2008 being impacted by a 50 percent drop in crude oil prices compared to the third quarter of 2008, resulting in a much lower inventory carrying value at December 31, 2008, thereby resulting in much higher purchased product costs;

•

Increase in the average liquids sales price, before hedging, to $61.08 per bbl compared to $30.47 per bbl in 2008; and

•

Increase in crude oil and NGLs production of 11 percent.

Partially offsetting the increases were the following:

•

An increase in current tax of $360 million on the acceleration of current tax payable, resulting in no income tax payable at December 31, 2009, due to the dissolution of EnCana’s Canadian oil and gas partnership in connection with the Arrangement;

•

A decrease in natural gas average sales prices, excluding hedging, of 30 percent; and

•

A decrease in natural gas production of 13 percent.

Our Net Earnings in the fourth quarter of 2009 were $24 million, which were $356 million lower than 2008. The factors that increased Cash Flow in the fourth quarter increased Net Earnings but were offset by the following factors that resulted in an overall decrease to Net Earnings:

•

Unrealized hedging loss of $143 million compared to a gain of $386 million in the fourth quarter of 2008; and

•

Higher Operating, General and Administrative and DD&A expenses.



Cenovus Energy Inc.		19
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

OIL AND GAS RESERVES

PROVED AND PROBABLE RESERVES AS AT DECEMBER 31


	Bitumen						Crude Oil and NGLs⁽¹⁾						Natural Gas
Constant Prices	(millions of barrels)						(millions of barrels)						(billions of cubic feet)
After Royalties	2009		2008		2007		2009		2008		2007		2009		2008		2007
Proved		719		668		596		232		241		231		1,474		1,855		2,019
Probable		403		624		537		127		136		119		405		522		569


(1)		Crude Oil and NGLs include condensate.

All of our bitumen, crude oil, NGLs and natural gas reserves are located in Canada. Each year, we engage independent qualified reserves evaluators to prepare reports on 100 percent of our reserves. We have a Reserves Committee of independent members of our Board, which reviews the qualifications and appointment of the independent qualified reserves evaluators. The Reserves Committee also reviews the procedures for providing information to the evaluators. Our disclosure of reserves data is prescribed by National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) of the Canadian Securities Administrators as amended by a Decision dated October 20, 2009 permitting the adoption of U.S. reporting standards, including compliance with the practices and procedures of the U.S. Securities and Exchange Commission (“SEC”) and U.S. Financial Accounting Standards Board (“FASB”) reserves reporting requirements.

As of December 31, 2009, the SEC requires companies to determine their oil and gas reserves using an average price based upon the prior 12-month period, rather than year-end prices. The SEC also now permits companies to disclose their probable and possible reserves in their SEC filings.

PROVED RESERVES RECONCILIATION


				Crude Oil and
Constant Prices after Royalties	Bitumen			NGLs⁽¹⁾			Natural Gas
As at December 31, 2009	(millions of barrels)			(millions of barrels)			(billions of cubic feet)
Beginning of year		668			241			1,855
Revisions and improved recovery		(88	)		8			(128	)
Extensions and discoveries		160			6			50
Divestitures		(4	)		—			(2	)
Production		(17	)		(23	)		(301	)

End of year		719			232			1,474


(1)		Crude Oil and NGLs includes condensate.

In 2009, our bitumen reserves extensions and discoveries were approximately 160 million barrels, primarily as a result of Christina Lake phase D receiving approval to proceed. The increase was partially offset by negative revisions of approximately 88 million barrels attributed to higher royalty rates resulting from a higher WTI price. In addition, as a result of the new Alberta Royalty Framework, where royalties are determined on a sliding scale depending on the price of bitumen, when prices are between C$55 per barrel and C$120 per barrel, pre-payout royalty rates range from one to nine percent of gross revenue. Once a project reaches payout the royalty is based on the greater of one to nine percent of a project’s gross revenue or 25 to 40 percent of net revenue. Our crude oil and NGLs reserves decreased by approximately four percent year over year as aggregate revisions and improved recoveries and extensions and discoveries did not fully offset our production. Our natural gas reserves negative revisions were approximately 128 billion cubic feet mainly due to low natural gas prices.

Additional disclosure relating to our oil and gas reserves is contained in our Annual Information Form for the year ended December 31, 2009 which can be accessed at www.sedar.com and on our website at www.cenovus.com.



Cenovus Energy Inc.		20
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

LIQUIDITY AND CAPITAL RESOURCES


($ millions)	2009			2008			2007
Net cash from (used in)
Operating activities	$	3,496		$	2,687		$	3,014
Investing activities		(1,780	)		(1,964	)		(1,533	)

Net cash provided before Financing activities		1,716			723			1,481
Financing activities		(1,730	)		(852	)		(1,292	)
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency		9			(20	)		7

Increase (decrease) in cash and cash equivalents	$	(5	)	$	(149	)	$	196

OPERATING ACTIVITIES

Net cash from operating activities increased to $3,496 million in 2009 compared to $2,687 million in 2008 (2007 — $3,014 million). Cash Flow was $2,472 million during 2009 compared to $3,088 million in 2008. Reasons for this change are discussed under the Cash Flow section of this MD&A. Cash from operating activities was also impacted by net changes in other assets and liabilities and net changes in non-cash working capital, primarily from increases in inventories, accounts receivable and accrued revenues and current income taxes partially offset by increases in accounts payable and accrued liabilities.

Excluding the impact of risk management assets and liabilities, we had working capital of $457 million at December 31, 2009 compared to a working capital deficit of $191 million at December 31, 2008. We anticipate that we will continue to meet the payment terms of our suppliers.

INVESTING ACTIVITIES

Net cash used for investing activities in 2009 decreased to $1,780 million from $1,964 million in 2008. Capital expenditures decreased in 2009 to $1,895 million compared to $2,046 million in 2008. Divestitures were $162 million higher than 2008 and were substantially offset with increases in cash used for investing activities from net changes in non-cash working capital. The decreased capital expenditures are discussed under the Net Capital Investment and Divisional Results sections of this MD&A.

FINANCING ACTIVITIES

On September 18, 2009, a predecessor entity of Cenovus completed a private offering of senior unsecured notes for an aggregate principal amount of $3.5 billion, issued in three tranches, which are exempt from the registration requirements of the U.S. Securities Act of 1933 under Rule 144A and Regulation S. The net proceeds of the private offering, along with $151 million deposited by the Company, were placed into an escrow account pending the completion of the Arrangement with EnCana. Upon completion of the Arrangement, funds were released from escrow and the proceeds of the notes were then used to pay the note payable to EnCana of $3.5 billion as part of the Arrangement. On November 30, 2009, the notes became the direct, unsecured obligations of Cenovus.

We currently have in place an unsecured credit facility in the amount of Canadian $2.5 billion or its equivalent amount in U.S. dollars. The revolving syndicated credit facility consists of two tranches, a Canadian $2.0 billion 3-year tranche and a Canadian $500 million 364-day tranche. At December 31, 2009, we had available $2.3 billion (Canadian $2.4 billion) in unused credit capacity under this facility. We are currently in compliance with all of our financial covenants under this credit facility.

We declared and paid a dividend of $151 million ($0.20 per share) in December 2009. The December dividend reflects an amount determined in connection with the Arrangement based on carved-out earnings and cash flows. Future dividends will be at the sole discretion of the Board and considered quarterly.

It is Cenovus’s intention to maintain investment grade credit ratings on our senior unsecured debt. DBRS Limited has assigned a rating of “A (low)” with a “Stable” outlook, Standard & Poor’s Corporation has assigned a rating of BBB+ with a “Stable” outlook and Moody’s Investors Service, Inc. has assigned a rating of Baa2 with a “Stable” outlook.



Cenovus Energy Inc.		21
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

As at December 31, 2008, our current and long-term debt represented an allocation of our proportionate share of EnCana’s consolidated current and long-term debt. As a result, the debt allocations presented in the Consolidated Financial Statements at December 31, 2008 represented intercompany balances between EnCana and Cenovus with the same terms and conditions as EnCana’s long-term debt and in the same proportion of Canadian and U.S. dollar denominated debt.

Our net cash used in financing activities for 2009 of $1,730 million, includes $3,468 million of net proceeds from the private offering of the notes, as well as the repayment of the $3.5 billion demand promissory note to EnCana. Subsequent to the completion of the Arrangement, Cenovus made a payment to EnCana in the amount of $250 million to adjust the cash balances of both companies at November 30, 2009 to the agreed upon amounts pursuant to the Arrangement. Our debt, including current portion, was $3,493 million as at December 31, 2009 compared with $3,036 million as at December 31, 2008.

FINANCIAL METRICS


	2009			2008			2007
Debt to Capitalization		28	%		28	%		32	%
Debt to Adjusted EBITDA (times)		1.2	x		0.7	x		1.0	x

Cenovus monitors its capital structure and short-term financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted EBITDA. Capitalization is a non-GAAP measure defined as long-term debt including current portion plus Shareholders’ Equity. Trailing 12-month Adjusted EBITDA is a non-GAAP measure defined as Adjusted Earnings before Interest, Income Taxes, DD&A and foreign exchange gains/losses. These metrics are used to steward Cenovus’s capital structure. Debt is defined as the current and long-term portions of long-term debt.

We target a Debt to Capitalization ratio between 30 to 40 percent and a Debt to Adjusted EBITDA between 1.0 to 2.0 times.

OUTSTANDING SHARE DATA


(millions)	2009
Common Shares issued pursuant to the Arrangement		751.3

Outstanding, End of year		751.3

Cenovus is authorized to issue an unlimited number of Common Shares (the “Common Shares”), an unlimited number of first preferred shares and an unlimited number of second preferred shares. There were no first preferred shares or second preferred shares outstanding as at December 31, 2009.

Pursuant to the Arrangement, each shareholder of EnCana received one new common share of EnCana (which continued to be represented by EnCana common share certificates outstanding prior to the Arrangement becoming effective) and one Common Share of Cenovus for every EnCana common share held. In aggregate, 751,273,307 Common Shares were issued pursuant to the Arrangement.

The Cenovus Employee Stock Option Plan permits our Board, from time to time, to grant to employees of Cenovus and its subsidiaries stock options to purchase our Common Shares. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. As at December 31, 2009, our options are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years and expire five years after the date granted. Stock options granted have an associated Tandem Share Appreciation Right (“TSAR”) attached, which gives employees the right to elect to receive a cash payment equal to the excess of the market price of our Common Shares over the exercise price of their stock option in exchange for surrendering their stock option. A portion of the TSARs have an additional vesting condition which is subject to the Company attaining prescribed performance relative to key pre-determined measures. Performance TSARs that do not vest when eligible are forfeited. The exercise of a TSAR for a cash payment does not result in the issuance of any additional Common Shares, thus it has no dilutive effect.



Cenovus Energy Inc.		22
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

In accordance with the Arrangement with EnCana, each holder of EnCana TSARs and stock options disposed of a portion of their right to Cenovus in exchange for Cenovus Replacement Units and to EnCana for EnCana Replacement Units. The terms and conditions of the Cenovus Replacement Units are similar to the terms and conditions of the original EnCana units, which are also similar, to the terms and conditions of Cenovus TSARs and stock options. The original exercise price of the EnCana units were apportioned to the Cenovus and EnCana Replacement Units based on the one-day weighted average trading price of Cenovus’s common share price relative to that of EnCana’s common share price on the TSX on December 2, 2009.

At December 31, 2009, Cenovus employees held approximately 16 million Cenovus TSARs, of which 6 million were exercisable.

At December 31, 2009 EnCana employees held approximately 23 million Cenovus TSARs, of which 10 million were exercisable. EnCana is required to reimburse Cenovus in respect of cash payments made to EnCana employees for the Cenovus TSARs held. No further Cenovus TSARs will be granted to EnCana’s employees. Cenovus is required to reimburse EnCana in respect of cash payments made to Cenovus employees for the Cenovus Replacement Units held. No further EnCana Replacement Units will be granted to Cenovus’s employees.

At December 31, 2009 there were approximately 0.2 million options without TSARs attached outstanding, all of which were exercisable.

Cenovus employees hold Cenovus Share Appreciation Rights, Cenovus Deferred Share Units, EnCana Tandem Share Appreciation Rights and EnCana Share Appreciation Rights and Cenovus directors hold Cenovus Deferred Share Units for which Cenovus is responsible. These units do not result in the issuance of any additional Cenovus Common Shares and therefore have no dilutive effect.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS⁽¹⁾


	Expected Payment Date
($ millions)	2010		2011		2012		2013		2014		2015+		Total
Long-Term Debt ⁽²⁾	$	—	$	—	$	56	$	—	$	800	$	2,700	$	3,556
Partnership Contribution Payable ⁽²⁾		325		345		366		388		412		1,021		2,857
Asset Retirement Obligation		68		11		11		12		16		5,312		5,430
Pipeline Transportation		101		95		68		141		141		923		1,469
Purchase of Goods and Services		98		9		4		3		—		—		114
Product Purchases		26		23		22		22		22		28		143
Operating Leases ⁽³⁾		26		27		34		72		76		1,575		1,810
Capital Commitments		105		85		33		—		—		—		223

Total Payments	$	749	$	595	$	594	$	638	$	1,467	$	11,559	$	15,602

Product Sales	$	46	$	48	$	52	$	53	$	55	$	119	$	373
Partnership Contribution Receivable ⁽²⁾	$	330	$	347	$	366	$	386	$	407	$	998	$	2,834


(1)		In addition, we have commitments related to our risk management program (see notes to the Consolidated Financial Statements), and an obligation to fund our defined benefit pension and Other Post-Employment Benefit plans as disclosed in the notes to the Consolidated Financial Statements.

(2)		Principal component only. See notes to the Consolidated Financial Statements.

(3)		Operating leases consist of building leases.

We have entered into various commitments in the normal course of operations primarily related to debt, demand charges on firm transportation agreements, capital commitments and marketing agreements.

As at December 31, 2009, Cenovus remained a party to long-term, fixed price, physical contracts for natural gas with a current delivery of approximately 33 MMcf/d, with varying terms and volumes through 2017. The total volume to be delivered within the terms of these contracts is 85 Bcf at a weighted average price of $4.39 per Mcf.



Cenovus Energy Inc.		23
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

In the normal course of business, we also lease office space for personnel who support field operations and for corporate purposes.

LEGAL PROCEEDINGS

We are involved in various legal claims associated with the normal course of operations and we believe we have made adequate provisions for such claims.

RISK MANAGEMENT

Our business, prospects, financial condition, results of operations and cash flows, and in some cases our reputation, are impacted by risks that are categorized as follows:

•

Financial risks including market risks (such as commodity price, foreign exchange and interest rates), credit and liquidity risks;

•

Operational risks including capital, operating and reserves replacement risks; and

•

Safety, environmental and regulatory risks.

We are committed to identifying and managing these risks in the near-term as well as on a strategic and longer term basis at all levels in the organization in accordance with our Board approved Corporate Risk Management Policy and risk management programs. Issues affecting, or with the potential to affect, our assets, operations and/or reputation, are generally of a strategic nature or emerging issues that can be identified early and then managed, but occasionally include unforeseen issues that arise unexpectedly and must be managed on an urgent basis. We take a proactive approach to the identification and management of issues that can affect our assets, operations and/or reputation and have established consistent and clear policies, procedures, guidelines and responsibilities for identifying and managing these issues.

FINANCIAL RISKS

Financial risks are defined as the risk of loss or lost opportunity resulting from financial management and market conditions that could have a positive or negative impact on our business.

We continue to implement our business model which focuses on developing low-risk and low-cost long-life resource properties. Management has been monitoring our operational and financial risk strategies to proactively respond to the changing economic conditions and to mitigate or reduce risk. The prudent and conservative capital budget for 2010 continues to be monitored and it contains the flexibility to allow spending to be reduced or increased as commodity prices and forecasts are revised. Cost containment and reduction strategies are in place to help ensure our controllable costs are efficiently managed. Counterparty and credit risks are closely monitored as is our liquidity to help ensure our ability to access cost effective credit is maintained and that sufficient cash resources are in place to fund capital expenditures. Further insight into these risks and strategies is summarized below.

We partially mitigate our exposure to financial risks through the use of various financial instruments and physical contracts. The use of derivative instruments is governed under formal policies and is subject to limits established in our Market Risk Mitigation Policy. As a means of mitigating exposure to commodity price risk volatility, we have entered into various financial instrument agreements in respect of our operations. The details of these instruments, including any unrealized gains or losses, as of December 31, 2009, are disclosed in the notes to the Consolidated Financial Statements.

Policies, practices and procedures are in place with respect to the required documentation and approvals for the use of derivative financial instruments and specifically tie their use, in the case of commodities, to the mitigation of price risk to achieve targeted investment returns and growth objectives, while maintaining prescribed financial metrics.



Cenovus Energy Inc.		24
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

With respect to transactions involving our production or assets, the financial instruments generally used are swaps or options which are entered into with major financial institutions, integrated energy companies or commodities trading institutions.

COMMODITY PRICE

Commodity price risk is defined as the uncertainties and fluctuations of future market prices for commodities. To partially mitigate the commodity price risk, we enter into swaps and puts, which establish NYMEX floor prices. For crude oil, we have partially mitigated our exposure to commodity price risk on our crude oil sales and condensate supply with fixed price swaps. For natural gas, to partially mitigate the natural gas commodity price risk, the Company has entered into swaps, which fix the NYMEX prices. To help protect against widening natural gas price differentials in various production areas, Cenovus has entered into basis swaps to manage the price differentials between these production areas and various sales points. We have mitigated some of our exposure to electricity consumption costs, with two derivative contracts which do not expire until December 31, 2018.

CREDIT

Credit risk is defined as the potential for loss if a counterparty in a transaction fails to meet its obligations in accordance with agreed terms. A substantial portion of our accounts receivable is with customers in the oil and gas industry. This credit exposure is mitigated through the use of our Board-approved credit policies governing our credit portfolio and with credit practices that limit transactions according to counterparties’ credit quality and transactions that are fully collateralized. All financial derivative agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings.

LIQUIDITY

Liquidity risk is the risk we will not be able to meet all our financial obligations as they come due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. We manage our liquidity risk through the active management of cash and debt by ensuring that we have access to multiple sources of capital including: cash and cash equivalents, cash from operating activities and undrawn credit facilities. At December 31, 2009, Cenovus had approximately $2.3 billion in unused credit capacity available on its committed bank credit facility.

FOREIGN EXCHANGE

Foreign exchange risk is defined as the risk of gains or losses that could result from changes in foreign currency exchange rates. As we operate in North America, fluctuations in the exchange rate between the U.S. and Canadian dollar can have a significant effect on our reported results.

As a means of mitigating the exposure to fluctuations in the U.S./Canadian dollar exchange rate, we may enter into foreign exchange contracts, in conjunction with crude oil marketing transactions. In addition, we may hedge commodity exposures in Canadian dollars. Gains or losses on these contracts are recognized when the difference between the average month spot rate and the rate on the date of settlement is determined. All foreign exchange agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings. By maintaining U.S. and Canadian operations, we have a natural hedge to some foreign exchange exposure.

We also have the flexibility to maintain a mix of both U.S. dollar and Canadian dollar debt, which helps to offset the exposure to the fluctuations in the U.S./Canadian dollar exchange rate. In addition to direct issuance of U.S. dollar denominated debt, we may enter into cross currency swaps on a portion of our debt as a means of managing the U.S./Canadian dollar debt mix.



Cenovus Energy Inc.		25
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

INTEREST RATES

Interest rate risk is defined as the impact of changing interest rates on earnings, cash flows and valuations. Although the majority of our debt portfolio was fixed rate debt at December 31, 2009, we have the flexibility to partially mitigate our exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt through the use of our bank credit facilities. We may also enter into interest rate swap transactions from time to time as an additional means of managing the fixed/floating rate debt portfolio mix.

OPERATIONAL RISKS

Operational risk is the risk of loss or lost opportunity resulting from operating and capital activities that, by their nature, could have an impact on our ability to achieve our objectives.

Our ability to operate, generate cash flows, complete projects and value reserves is dependent on financial risks, including commodity prices mentioned above, continued market demand for our products and other risk factors outside of our control, which include: general business and market conditions; economic recessions and financial market turmoil; the ability to secure and maintain cost effective financing for our commitments; the ability to obtain necessary approvals; environmental and regulatory matters; unexpected cost increases; royalties; taxes; the availability of drilling and other equipment; the ability to access lands; weather; the availability of processing capacity; the availability and proximity of pipeline capacity; the availability of diluents to transport crude oil; technology failures; accidents; the availability of skilled labour; and reservoir quality.

If we fail to acquire or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels and, therefore, our cash flows are highly dependent upon successfully exploiting current reserves and acquiring, discovering or developing additional reserves.

To mitigate these risks, as part of the capital approval process, we evaluate projects on a fully risked basis, including geological risk and engineering risk. In addition, the asset teams undertake a process called Lookback and Learning. In this process, each asset team undertakes a thorough review of its previous capital program to identify key learnings, which often include operational issues that positively and negatively impacted the project’s results. Mitigation plans are developed for the operational issues that had a negative impact on results. These mitigation plans are then incorporated into the current year plan for the project. On an annual basis, these Lookback and Learning results are analyzed for our capital program with the results and identified learnings shared across our company.

We utilize a peer review process to ensure that capital projects are appropriately risked and that knowledge is shared across our company. Peer reviews are undertaken primarily for early stage properties, although they may occur for any type of project.

When making operating and investing decisions, our business model allows flexibility in capital allocation to optimize investments focused on strategic fit, project returns, long-term value creation, and risk mitigation. We also mitigate operational risks through a number of other policies, systems and processes as well as by maintaining a comprehensive insurance program in respect of our assets and operations.

SAFETY, ENVIRONMENTAL AND REGULATORY RISKS

We are engaged in relatively high risk activities of integrated enhanced oil development and natural gas production. We are committed to safety in our operations and with high regard for the environment and stakeholders, including regulators. These risks are managed by executing policies and standards that are designed to comply with or exceed government regulations and industry standards. In addition, we maintain a system, in respect of our assets and operation, that identifies, assesses and controls safety, security and environmental risk and requires regular reporting to Senior Management and our Board. The Safety, Environment and Responsibility Committee of our Board provides recommended environmental policies for approval by our Board and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. Contingency plans are in place for a timely response to an environmental event and remediation/reclamation strategies are utilized to restore the environment. In addition, security risks are managed through a security program designed to protect our personnel and assets.



Cenovus Energy Inc.		26
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

We have an Investigations Committee with the mandate to address potential violations of policies and practices and an Integrity Helpline that can be used to raise any concerns regarding operations, accounting or internal control matters which includes any such matters associated with us.

Our operations are subject to regulation and intervention by governments that can affect or prohibit the drilling, completion and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Contract rights can be cancelled or expropriated. Changes to government regulation could impact our existing and planned projects as well as impose a cost of compliance.

Regulatory and legal risks are identified by the operating divisions and corporate groups, and our compliance with the required laws and regulations is monitored by our legal group in respect of our assets and operations. Our legal and environmental policy groups stay abreast of new developments and changes in laws and regulations to ensure that we continue to comply with prescribed laws and regulations. Of note in this regard, our approach to changes in regulations relating to climate change and royalty frameworks is discussed below. To partially mitigate resource access risks, keep abreast of regulatory developments and be a responsible operator, we maintain relationships with key stakeholders and conduct other mitigation initiatives mentioned herein.

CLIMATE CHANGE

Various federal, provincial and state governments have announced intentions to regulate greenhouse gas (“GHG”) emissions and other air pollutants and a number of legislative and regulatory measures to address GHG emissions are in various phases of review, discussion or implementation in the United States and Canada. These include proposed federal legislation and state actions in the United States to develop statewide or regional programs, each of which could impose reductions in GHG emissions. While some jurisdictions have provided details on these regulations, it is anticipated that other jurisdictions will announce emission reduction plans in the future. Adverse impacts to our business if comprehensive GHG legislation is enacted in any jurisdiction in which we operate, may include, among other things, increased compliance costs, permitting delays, substantial costs to generate or purchase emission credits or allowances adding costs to the products we produce and reduced demand for crude oil and certain refined products.

Beyond existing legal requirements, the extent and magnitude of any adverse impacts of any of these additional programs cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the time frames for compliance. We intend to continue our activity to reduce our emissions intensity and improve our energy efficiency. We will also continue to work with governments to develop an approach to deal with climate change issues that protects the industry’s competitiveness, limits the cost and administrative burden of compliance and supports continued investment in the sector.

The Alberta government has set targets for GHG emissions reductions. In March 2007, regulations were amended to require facilities that emit more than 100,000 tonnes of GHG emissions per year to reduce their emissions intensity by 12 percent from a regulated baseline starting July 1, 2007. To comply, companies can make operating improvements, purchase carbon offsets (or emission performance credits) or make a C$15 per tonne contribution to an Alberta Climate Change and Emissions Management Fund. Cenovus currently has three facilities subject to this regulation that will report performance against their targets in March 2010 and for the 2009 compliance year does not anticipate material costs.

The American Clean Energy and Security Act (the “Act”) was passed by the U.S. House of Representatives on June 26, 2009 and similar measures have been contemplated by the U.S. Senate. Some of the climate change bills being contemplated in the U.S. would require refiners to purchase credits equivalent to the CO₂ emissions from both their refineries and from consumer emissions. If this approach was enacted into law, this could have a material impact on the cost structure of refined petroleum products.



Cenovus Energy Inc.		27
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Our efforts with respect to emissions management are founded in our industry leadership in CO₂ sequestration, a focus on energy efficiency and the development of technology to reduce GHG emissions. In particular, our industry leading steam to oil ratio at Foster Creek and Christina Lake translates directly into lower emissions intensity. Given the uncertainty in North American carbon legislation, our strategy for addressing the implications of emerging carbon regulations is proactive and is composed of three principal elements:

Manage Existing Costs

When regulations are implemented, a cost is placed on our emissions (or a portion thereof) and while these are not material at this stage, they are being actively managed to ensure compliance. Factors such as effective emissions tracking attention to fuel consumption and a focus on minimizing our steam to oil ratio help to support and drive our focus on cost reduction.

Respond to Price Signals

As regulatory regimes for GHGs develop in the jurisdictions where we work, inevitably price signals begin to emerge. We have initiated an Energy Efficiency Initiative in an effort to improve the energy efficiency of our operations. The price of potential carbon reductions plays a role in the economics of the projects that are implemented. In response to the anticipated price of carbon reduction, we are also attempting, where appropriate, to realize the associated value of our reduction projects.

Anticipate Future Carbon Constrained Scenarios

We continue to work with governments, academics and industry leaders to develop and respond to emerging GHG regulations. By continuing to stay engaged in the debate on the most appropriate means to regulate these emissions, we gain useful knowledge that allows us to explore different strategies for managing our emissions and costs. These scenarios inform our long range planning and our analyses on the implications of regulatory trends.

We incorporate the potential costs of carbon into future planning. Management and the Board review the impact of a variety of carbon constrained scenarios on our strategy, with a current price range from $15 to $65 per tonne of emissions applied to a range of emissions coverage levels. A major benefit of applying a range of carbon prices at the strategic level is that it provides direct guidance to the capital allocation process. We also examine the impact of carbon regulation on our major projects. Although uncertainty remains regarding potential future emissions regulation, our plan is to continue to assess and evaluate the cost of carbon relative to our investments across a range of scenarios.

We recognize that there is a cost associated with carbon emissions. We are confident that GHG regulations and the cost of carbon at various price levels have been adequately accounted for as part of our business planning and scenarios analysis. We believe that our development strategy is an effective way to develop the resource, generate shareholder returns and coordinate overall environmental objectives with respect to carbon, air emissions, water and land. We are committed to transparency with our stakeholders and will keep them apprised of how these issues affect operations.

TRANSPARENCY AND CORPORATE RESPONSIBILITY

We are committed to operating in a responsible manner which maintains and enhances our reputation and credibility. A central aspect of this commitment involves engagement with our various stakeholders, including shareholders and other investors, financial institutions, employees, business partners, communities, Aboriginal peoples, governments and non-governmental organizations. We will continue to disclose information about our business activities to our stakeholders in a timely and transparent manner to maintain and advance our reputation as a responsible operator, as well as to develop trust with our stakeholders. We disclose information that is not only required by law and/or regulation, but also additional information that management regards as important to help stakeholders understand our activities, policies, opportunities and risks. Our engagement with stakeholders also allows us to determine how they are each affected by our business. Feedback that we receive from stakeholders enables us to better identify and manage our environmental and socio-economic risks.



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Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

We are reviewing our existing Corporate Responsibility (“CR”) policy to ensure that it not only continues to drive our commitments, strategy and reporting, but also that it maintains alignment with our business objectives and processes. Our reporting process will focus on improving performance through better data management, stakeholder engagement and continuous improvement. Our approach in this first year is to communicate our key performance indicators using the Cenovus website as the main reporting vehicle.

As our CR reporting process matures, additional indicators will be developed that better reflect Cenovus’s operations and challenges. These indicators will be integrated into our CR reporting and will expand our online presence through our website.

We are committed to integrating the principles of corporate responsibility into the way we conduct our business across all of our operations and we recognize the importance of reporting to stakeholders in a transparent and accountable way.

ALBERTA’S NEW ROYALTY PROGRAMS

The Alberta Government’s New Royalty Framework (“NRF”) and Transitional Royalty Program (“TRP”) came into effect on January 1, 2009. The NRF established new royalties for conventional oil, natural gas and bitumen that are linked to commodity prices, well production volumes and well depths for gas wells and oil quality for oil wells. These new rates apply to both new and existing conventional oil and gas activities and EOR properties in Alberta. The TRP allows for a one time option of selecting between transitional rates and the NRF rates on new natural gas or conventional oil wells drilled between 1,000 metres to 3,500 metres in depth. The TRP rates would apply until January 1, 2014, at which time all wells would be moved to the NRF.

On March 3, 2009, the Alberta Government announced an Energy Incentive Program that focuses on keeping drilling and service crews at work. There are two components of this program that affect us: the Drilling Royalty Credit and the New Well Incentive. The Drilling Royalty Credit is a depth related credit for the drilling of new conventional oil and gas wells between April 1, 2009 and March 31, 2011. The New Well Incentive provides a maximum five percent royalty rate for new gas and conventional oil wells that come on production between April 1, 2009 and March 31, 2011 for a period of 12 months or 0.5 billion cubic feet equivalent (“Bcfe”) for gas wells or 50,000 barrels of oil equivalent (“BOE”) for oil wells, whichever comes first.

Impacts as a result of the NRF, TRP and Energy Incentive Programs change the economics of operating in Alberta, and accordingly, are reflected in our capital programs in respect of our assets and operations.

We are committed to continuing to work with the Alberta Government during its competitive review process.

ACCOUNTING POLICIES AND ESTIMATES

Management is required to make judgments, assumptions and estimates in the application of GAAP that have a significant impact on our financial results. The basis of presentation for the Consolidated Financial Statements and our significant accounting policies can be found in the notes to the Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The following discussion outlines the accounting policies and practices involving the use of estimates that are critical to understanding our financial results.

Basis of Presentation

Our results for the period from December 1 to December 31, 2009 represent our operations, cash flows and financial position as a stand-alone entity.



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Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Our results for the periods prior to the Arrangement with EnCana, being January 1 to November 30, 2009 as well as the years ended December 31, 2008 and 2007 have been prepared on a “carve-out” accounting basis, whereby the results have been derived from the accounting records of EnCana using the historical results of operations and historical basis of assets and liabilities of the businesses transferred to Cenovus. The historical consolidated financial statements include allocations of certain EnCana expenses, assets and liabilities. In the opinion of Management, the consolidated and the historical carve-out consolidated financial statements reflect all adjustments necessary for a fair statement of the financial position and the results of operations and cash flows in accordance with Canadian GAAP.

The presentation of financial statements in accordance with Canadian GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Management believes that the assumptions underlying the historical consolidated financial statements are reasonable. However, as we operated as part of EnCana and were not a stand-alone company prior to November 30, 2009, the historical consolidated financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows had we been a stand-alone company during the periods presented.

Full Cost Accounting

Crude oil and natural gas properties are accounted for in accordance with the Canadian Institute of Chartered Accountants (“CICA”) guideline on full cost accounting in the oil and gas industry. Under this method, all costs, including internal costs and asset retirement costs, directly associated with the acquisition of, exploration for, and the development of crude oil and natural gas reserves, are capitalized on a country-by-country cost centre basis and costs associated with production are expensed. The capitalized costs, including estimated future development costs, are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves. Reserves estimates can have a significant impact on earnings, as they are a key component in the calculation of DD&A. A downward revision in reserves estimate could result in a higher DD&A charge to earnings. In addition, if net capitalized costs are determined to be in excess of the calculated ceiling, which is based largely on reserves estimates (see asset impairment discussion below), the excess must be written off as an expense charged against earnings. In the event of a property divestiture, proceeds are normally deducted from the full cost pool without recognition of a gain or loss unless there is a change in the DD&A rate of 20 percent or greater.

Oil and Gas Reserves

All of our oil and gas reserves are evaluated and reported on by independent qualified reserves evaluators. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. Reserves estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts.

Asset Impairments

Under full cost accounting, a ceiling test is performed to ensure that unamortized capitalized costs in each cost centre do not exceed their fair value. An impairment loss is recognized in Net Earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to an amount by which the carrying amount exceeds the sum of:

the fair value of proved and probable reserves; and

ii)

the costs of unproved properties that have been subject to a separate impairment test.

An impairment loss is recognized on downstream refining property, plant and equipment when the carrying amount is not recoverable and exceeds its fair value. The carrying amount is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from expected use and eventual disposition. If the carrying amount is not recoverable, an impairment loss is measured as the amount by which the refinery asset exceeds the discounted future cash flows from the refinery asset.



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Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Our property, plant and equipment has been assessed for impairment as at December 31, 2009 and it has been determined that no write-down was required under Canadian GAAP.

Asset Retirement Obligations

The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when incurred and a reasonable estimate of fair value can be made. Asset retirement obligations are legal obligations associated with the requirement to retire tangible long-lived assets such as producing well sites, crude oil and natural gas processing plants and refining facilities. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statement of Earnings. Amounts recorded for asset retirement obligations are based on estimates of reserves and on retirement costs, which will not be incurred for several years. Actual expenditures incurred are charged against the accumulated obligation.

Goodwill

Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment at least annually. Goodwill and all other assets and liabilities have been allocated to the country cost centre level, referred to as reporting units. To assess impairment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit to determine the implied fair value of Goodwill and comparing that amount to the book value of the reporting unit’s Goodwill. Any excess of the book value of Goodwill over the implied fair value of Goodwill is the impairment amount.

Our Goodwill has been assessed for impairment as at December 31, 2009 and it has been determined that no write-down was required.

Income Taxes

Income taxes are accounted for using the liability method. Under this method, future income taxes are estimated and recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in Net Earnings in the period that the change occurs.

Tax interpretations, regulations and legislation in the various jurisdictions in which we (and our subsidiaries) operate are subject to change. As such, income taxes are subject to measurement uncertainty.

Derivative Financial Instruments

We may use derivative financial instruments to manage exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Derivative financial instruments are not used for speculative purposes.

We enter into financial transactions to help reduce exposure to price fluctuations with respect to commodity purchase and sale transactions to achieve targeted investment returns and growth objectives, while maintaining prescribed financial metrics. These transactions generally are swaps, collars or options and are generally entered into with major financial institutions or commodities trading institutions.



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Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

We may also use derivative financial instruments, such as interest rate swap agreements, to manage the fixed and floating interest rate mix of our total debt portfolio and related overall cost of borrowing. Interest rate swap agreements involve the periodic exchange of payments, without the exchange of the normal principal amount upon which the payments are based, and are recorded as an adjustment of interest expense on the hedged debt instrument.

We may also purchase foreign exchange forward contracts to hedge anticipated sales to customers in the United States. Foreign exchange translation gains and losses on these instruments are recognized as an adjustment of the revenues when the sale is recorded.

Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using the mark-to-market method of accounting whereby instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in Net Earnings. Realized gains or losses from financial derivatives related to crude oil and natural gas prices are recognized in revenues as the related sales occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimate of fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts. The estimated fair value of financial assets and liabilities, by their very nature, is subject to measurement uncertainty.

In 2009, we elected not to designate any of our price risk management activities as accounting hedges and, accordingly, accounted for all derivatives using the mark-to-market accounting method. Mark-to-market gains and losses resulting from derivative financial instruments entered into by EnCana have been allocated to Cenovus based on the related product volumes.

We also have obligations for payments (to employees of Cenovus) under the share appreciation rights, stock options with TSARs attached, performance share appreciation rights, and performance TSARs of EnCana. The financial liability for this obligation is accrued using the fair value method, and therefore fluctuations in the fair value of the rights will affect the accrued compensation expense that is recognized. The fair value of the obligation fluctuates, as it is based on assumptions for risk-free discount rate, dividend yield, as well as the volatility of our Cenovus share price.

Pensions and Other Post-Employment Benefits

Accruals for the obligations under the employee benefit plans and the related costs are recorded net of plan assets.

The cost of pensions and other post-employment benefits is actuarially determined using the projected benefit method based on length of service, and reflects Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected future health care costs. The expected return on plan assets is based on the fair value of those assets. The accrued benefit obligation is discounted using the market interest rate on high quality corporate debt instruments as at the measurement date.

Pension expense for the defined benefit pension plan includes the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of the net transitional obligation, the amortization of adjustments arising from pension plan amendments and the amortization of the excess of the net actuarial gain or loss over 10 percent of the greater of the benefit obligation and the fair value of plan assets. The amortization period covers the expected average remaining service lives of employees covered by the plans.

Pension expense for the defined contribution pension plans is recorded as the benefits are earned by the employees covered by the plan.

Pension and other post-employment benefits costs, assets and liabilities have been allocated to us based on Management’s best estimate of how services were historically provided by existing employees. Costs, assets and liabilities associated with retired employees remain with EnCana. Where service amounts are provided by an individual to both EnCana and Cenovus, those costs including salaries, benefits, pension and long-term incentives have been allocated equally between EnCana and Cenovus.



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Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Performance TSARs and Performance SARs

These plans provide for a range of payouts, based on key predetermined performance measures. The cost of these plans is expensed based on expected payouts. However, the amounts to be paid, if any, may vary from the current estimate. Further details on these plans are disclosed in the notes to our Consolidated Financial Statements.

NEW ACCOUNTING STANDARDS ADOPTED

On January 1, 2009, we adopted the CICA Handbook Section 3064 “Goodwill and Intangible Assets”. The adoption of this standard has had no material impact on our Consolidated Financial Statements. Additional information on the effects of the implementation of the new standard can be found in the notes to the Consolidated Financial Statements.

RECENT ACCOUNTING PRONOUNCEMENTS

As of January 1, 2011, we will be required to adopt the following CICA Handbook sections which have been converged with International Financial Reporting Standards (“IFRS”):

Business Combinations

“Business Combinations”, Section 1582, replaces the previous business combinations standard. The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the statement of earnings. The adoption of this standard will impact the accounting treatment of future business combinations.

Consolidated Financial Statements

“Consolidated Financial Statements”, Section 1601, which together with Section 1602 below, replace the former consolidated financial statements standard. Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard should not have a material impact on our Consolidated Financial Statements.

Non-controlling Interests

“Non-controlling Interests”, Section 1602, establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, Net Earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard should not have a material impact on our Consolidated Financial Statements.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

In 2011, IFRS will replace Canadian GAAP for profit-oriented Canadian publicly accountable enterprises. We will be required to report our results in accordance with IFRS beginning with the 3 month period ending March 31, 2011.



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Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Our IFRS Transition Plan

We have developed a changeover plan to complete the transition to IFRS by January 1, 2011, including the preparation of required comparative information for 2010. The key elements of our changeover plan include:

•

Determine appropriate changes to accounting policies and required amendments to financial disclosures;

•

Identify and implement changes in associated processes and information systems;

•

Comply with internal control requirements;

•

Communicate collateral impacts to internal business groups; and

•

Educate and train internal and external stakeholders.

IFRS Accounting Policies

We have completed our analysis of accounting policy alternatives and determined the areas that will be most significantly affected by the adoption of IFRS. The areas identified as being significant have the greatest potential impact to our financial statements or the greatest risk in terms of complexity to implement. The most significant areas continue to include:

•

Upstream Property, Plant and Equipment (“PP&E”), including

	•		Transition on date of adoption of IFRS

	•		Pre-exploration costs

	•		Exploration and Evaluation costs

	•		DD&A

	•		Gains and losses on divestitures

•		Impairment testing

•		Asset retirement obligation

•		Stock-based compensation

•		Income taxes

Upstream PP&E

Upstream PP&E will be one of the most significant areas impacted by the adoption of IFRS. Under Canadian GAAP, we follow the CICA’s guideline on full cost accounting, while IFRS has no equivalent guideline. In order to facilitate the transition to IFRS by full cost accounting companies, the International Accounting Standards Board (“IASB”) released additional exemptions for first-time adopters of IFRS in July 2009. Included in the amendments is an exemption which permits full cost accounting companies to allocate their existing upstream PP&E net book value (full cost pool) over reserves to the unit of account level upon transition to IFRS. We expect to adopt this exemption using the fair value of reserves as an allocation method. Without this exemption, we would have been required to retrospectively determine the carrying amount of oil and gas assets at the date of transition, or use the fair value or revaluation amount as our new deemed cost under IFRS. By using the exemption, the net book value of our upstream PP&E at the date of transition to IFRS will be the same as it was under Canadian GAAP, subject to any potential IFRS impairments that are recognized at the date of transition.

In moving to IFRS, we will be required to adopt different accounting policies for pre-exploration activities, exploration and evaluation costs, DD&A and the accounting for gains and losses on divestitures of properties.

Pre-exploration costs are costs incurred before the Company obtains the legal right to explore an area. Under Canadian GAAP, these costs are capitalized, while under IFRS, these costs must be expensed. At this time, we do not anticipate that this accounting policy difference will have a significant impact on our Consolidated Financial Statements.

During the exploration and evaluation phase (“E&E”), we capitalize costs incurred for these projects under Canadian GAAP. Under IFRS, we have the alternative to either continue capitalizing these costs until technical feasibility and commercial viability of the project has been determined, or expensing these costs as incurred. At this time, our IFRS accounting policy in relation to E&E activities has not been finalized.



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Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Under Canadian GAAP, we calculate our DD&A rate at the country cost centre level. Under IFRS, this rate will be calculated at a lower unit of account level. At this time, we have not finalized our policy in this regard, and therefore the impact of this difference in accounting policy is not reasonably determinable.

Full cost accounting under Canadian GAAP requires that gains or losses on divestitures of properties are only recognized when the disposal would affect our DD&A rate by 20 percent or more. Under IFRS, there is no such exemption, and therefore we will be required to recognize all gains and losses on property divestitures. At this time, the impact of this difference in accounting policy is not reasonably determinable.

As a result of the additional exemption released by the IASB, we anticipate that all changes to our Upstream PP&E accounting policies will be adopted prospectively.

Impairment Testing

For the first step of all of our impairment tests (Upstream, Downstream, Goodwill) under Canadian GAAP, future cash flows are not discounted. Under IFRS, the future cash flows are discounted. In addition, for upstream PP&E, impairment testing is currently performed at the country cost centre level, while under IFRS, it will be performed at a lower level, referred to as a cash-generating unit. We expect to adopt these changes in accounting policy prospectively. At this time, the impact of accounting policy differences related to impairment testing is not reasonably determinable.

Asset Retirement Obligation

Under Canadian GAAP, the discount rate used to estimate the liability is not updated to current market discount rates, while under IFRS, the rate is updated each reporting period. We expect to adopt this change in accounting policy prospectively. We do not anticipate that this accounting policy difference will have a significant impact on our consolidated financial statements.

Stock-based Compensation

Under Canadian GAAP, obligations for cash payments under stock-based compensation plans are accrued using the intrinsic method, while under IFRS, these obligations must be accounted for using the fair value method. While the carrying value each reporting period will be different under IFRS, the cumulative expense recognized over the life of the instrument under both methods will be the same. We expect to adopt this change in accounting policy prospectively. At this time, the impact of this difference is not reasonably determinable.

Income Tax

In transitioning to IFRS, the carrying amount of our tax balances will be directly impacted by the tax effects resulting from changes required by the above IFRS accounting policy differences. Therefore, at this time the income tax impacts of our differences are not reasonably determinable.

Changes to IFRS Accounting Standards

Our analysis of accounting policy differences specifically considers the current IFRS standards that are in effect. We will continue to monitor any new or amended accounting standards that are issued by the IASB, including assessing any impact of the new joint ventures standard that the IASB expects to publish in the first quarter of 2010.

Preparation of the IFRS Opening Balance Sheet

We expect to commence working on the determination of our IFRS opening balance sheet in the first quarter of 2010.



Cenovus Energy Inc.		35
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Information Systems

We have completed the design of process and system changes that we expect will be required. We have performed preliminary testing of the changes and expect to finalize our testing in the first half of 2010. We plan to fully implement the system changes by June 30, 2010.

Internal Controls Over Financial Reporting

We are in the process of updating our internal controls documentation, and we do not anticipate that the transition to IFRS will have a significant impact on either our internal controls over financial reporting, or our disclosure controls and procedures.

Education and Training

All of the individuals that are involved in our financial reporting under Canadian GAAP have been engaged and involved in the IFRS transition project since 2008, and will continue to be involved in our IFRS transition throughout 2010 and 2011. Other individuals affected by the change from Canadian GAAP to IFRS will be educated and trained during 2010 as we identify and calculate the specific dollar value of differences arising from the changes to our accounting policies.

Impacts to our Business

We are not expecting that the adoption of IFRS in 2011 will have a significant impact or influence on our business activities, operations or strategies.

OUTLOOK

Our long term objective is to focus on building net asset value and generating an attractive total shareholder return through the following strategies:

•

Visible material growth in enhanced oil resource development, particularly with expansions at our Foster Creek and Christina Lake SAGD bitumen operations. We also have an extensive inventory of emerging bitumen plays;

•

Leadership in low-cost SAGD development; enabled by technology and continued respect for our employee’s safety, our stakeholders and the environment;

•

Internally funded growth through free cash flow from our established crude oil and natural gas assets; and

•

Maintaining a lower risk profile through natural gas and downstream integration as well as hedging execution.

We believe global oil demand will continue to increase. However, commodity price volatility, environmental regulations, government intervention and competitive pressures within our industry are the key hurdles that need to be effectively managed to enable our growth. Additional detail regarding the impact of these factors on our 2009 results is discussed in the Risk Management section of this MD&A. WTI and light-heavy differentials are likely to be relatively strong for the foreseeable future. Offsetting this is a relatively weak price outlook for natural gas and refining margins.

We expect our 2010 capital investment program to be funded from Cash Flow. Our crude oil and natural gas assets in Alberta and Saskatchewan will be key to providing free cash flow to enable our bitumen growth. We have chosen to accelerate completion of Christina Lake phase D which we expect will advance start up by approximately six months.

As part of ongoing efforts to maintain financial resilience and flexibility, Cenovus has taken steps to reduce pricing risk through a commodity hedging program. While we have benefitted from this strategy in 2009 and 2008, we cannot ensure that we will continue to derive such benefits in the future.

One of the factors that will affect our future results will be our effective royalty rates. Based on current market pricing, we expect that the Foster Creek project will reach payout during 2010. Once the project reaches payout the applicable monthly royalty will be based on the greater of 1-9 percent of the project’s gross revenue or 25-40 percent of the net revenue. The actual royalty rate that is payable within these ranges is determined based on the WTI U.S. dollar price of crude oil, translated into Canadian dollars.



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Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

As a new entity, the Company will continue to develop strategy with respect to capital investment and returns to shareholders. Future dividends will be at the sole discretion of the Board and considered quarterly.

ADVISORY

FORWARD-LOOKING STATEMENTS

In the interest of providing Cenovus shareholders and potential investors with information regarding the Company and its subsidiaries, including Management’s assessment of Cenovus’s and its subsidiaries’ future plans and operations, certain statements contained in this document constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements in this document include, but are not limited to, statements with respect to: projections relating to the adequacy of our provision for taxes; the effect of our policies and programs to reduce safety, environmental and regulatory risks, including climate change; our estimate of the cost of carbon; the potential impact of the Alberta Royalty Framework, NRF, TRP and Energy Incentive Programs; projections and plans with respect to growth of natural gas production from unconventional properties and enhanced oil resources including with respect to the Foster Creek and Christina Lake properties, the CORE project and planned expansions of our downstream heavy oil processing capacity and the capital costs and expected timing of the same; our ability to meet consumer demand; projections relating to the volatility of crude oil prices in 2010 and beyond and the reasons therefor; commodity prices, including the WTI and light-heavy differentials; our projected capital investment levels for 2010, the flexibility of capital spending plans and the source of funding therefor; the effect of our risk management program, including the impact of derivative financial instruments and our access to various sources of capital; the adequacy of provisions made for legal proceedings against us; the impact of the changes and proposed changes in laws and regulations, including greenhouse gas, carbon and climate change initiatives on our operations and operating costs; our ability to realize the expected benefits of the Arrangement; potential dividends; our expected future attributes, business plan and operational focus; our ability to fund our 2010 capital program; the effect of our risk mitigation policies, systems, processes and insurance program; our expectations for future Debt to Capitalization and Debt to Adjusted EBITDA ratios; the expected impact and timing of various accounting pronouncements, rule changes and standards on us and our Consolidated Financial Statements; and projections relating to global oil demand, prices for natural gas and refining margins. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions based upon our current guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in our and our subsidiaries’ marketing operations, including credit risks; imprecision of reserves estimates and estimates of recoverable quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our and our subsidiaries’ ability to replace and expand oil and gas reserves; the ability of ourselves and ConocoPhillips to successfully manage and operate the North American integrated heavy oil business and the ability of the parties to obtain necessary regulatory approvals; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected



Cenovus Energy Inc.		37
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with technology and the application thereof to our business; our ability to generate sufficient cash flow from operations to meet our current and future obligations; our ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; our and our subsidiaries’ ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations or the interpretations of such laws or regulations; political and economic conditions in the countries in which we and our subsidiaries operate; the risk of war, terrorist threats, hostilities, civil insurrection and instability affecting countries in which we and our subsidiaries operate; risks associated with existing and potential future lawsuits and regulatory actions made against us and our subsidiaries; the financing plans and initiatives that may be undertaken by us, the capitalization and adequacy thereof for us, the expected impacts of the Arrangement on our employees, operations, suppliers, business partners and stakeholders, our ability to obtain financing in the future on a stand alone basis, that the historical financial information pertaining to our assets as operated by EnCana prior to November 30, 2009 may not be representative of our results as an independent entity, that we have a limited operating history, as a separate entity, and other risks and uncertainties described from time to time in the reports and filings we have made with securities regulatory authorities. Statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Although we believe that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this document are made as of the date of this document, and except as required by law, we do not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

We previously disclosed and updated guidance relating to anticipated results for 2009. There were no material differences between (a) our actual cash flow, capital investment and operating costs in 2009 and (b) the amounts forecast in our most recently disclosed guidance (dated December 1, 2009). Explanations for any changes contained in any updated guidance, from guidance previously disclosed, were provided in the news release issued by Cenovus at the time the guidance was updated.

Our forward-looking information respecting anticipated 2010 cash flow, operating cash flow and pre-tax cash flow is based upon achieving average 2010 production of approximately 105,000 bbls/d to 111,500 bbls/d of crude oil and liquids and 720 MMcf/d to 740 MMcf/d of natural gas, average commodity prices for 2010 of a WTI price of $65 per bbl to $85 per bbl and a WCS price of $54 per bbl to $71 per bbl for oil, a NYMEX price of $5.50 per Mcf to $6.15 per Mcf and AECO price of $5.15 per GJ to $5.70 per GJ for natural gas, an average U.S./Canadian dollar foreign exchange rate of $0.85 to $0.96 US$/CDN$, an average Chicago 3-2-1 crack spread for 2010 of $7.50 per bbl to $9.50 per bbl for refining margins, and an average number of outstanding shares of approximately 750 million. Assumptions relating to forward-looking statements generally include our current expectations and projections made by the Company in light of, and generally consistent with, its historical experience and its perception of historical trends, as well as expectations regarding rates of advancement and innovation, generally consistent with and informed by its past experience, all of which are subject to the risk factors identified elsewhere in this document.

We are required to disclose events and circumstances that occurred during the period to which this MD&A relates that are reasonably likely to cause actual results to differ materially from material forward-looking statements for a period that is not yet complete that we have previously disclosed to the public and the expected differences thereto. Such disclosure can be found in our news release dated February 11, 2010 which is available on www.sedar.com.

OIL AND GAS INFORMATION

Our disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to us by Canadian securities regulatory authorities that permits us to provide such disclosure in accordance with U.S. disclosure requirements. The information provided by us may differ from the corresponding information prepared in accordance with Canadian disclosure standards under NI 51-101.



Cenovus Energy Inc.		38
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

The reserves quantities disclosed by us represent net proved and probable reserves calculated using the standards contained in Regulation S-X of the U.S. Securities & Exchange Commission. Further information about the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading “Note Regarding Reserves Data and Other Oil and Gas Information” in our Annual Information Form for the year ended December 31, 2009.

CRUDE OIL, NGLs AND NATURAL GAS CONVERSIONS

In this document, certain natural gas volumes have been converted to barrels of oil equivalent (“BOE”) on the basis of one barrel to six thousand cubic feet. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent value equivalency at the well head.

CURRENCY

All information included in this document and the Consolidated Financial Statements and comparative information is shown on a U.S. dollar, after royalties basis unless otherwise noted.

NON-GAAP MEASURES

Certain measures in this document do not have any standardized meaning as prescribed by Canadian GAAP such as Cash Flow, Operating Cash Flow, Free Cash Flow, Operating Earnings, Adjusted EBITDA, Debt and Capitalization and therefore are considered non-GAAP measures. Therefore, these measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in this document in order to provide shareholders and potential investors with additional information regarding our liquidity and our ability to generate funds to finance our operations. Management’s use of these measures has been disclosed further in this document as these measures are discussed and presented.

REFERENCES TO CENOVUS

For convenience, references in this document to “Cenovus”, “we”, “us”, “our” and “its” may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations and partnerships (“Subsidiaries”) of Cenovus, and the assets, activities and initiatives of such Subsidiaries.

Additional information regarding Cenovus Energy Inc. can be accessed under our public filings, including our Annual Information Form for the year ended December 31, 2009, found at www.sedar.com and on our website at www.cenovus.com.



Cenovus Energy Inc.		39
Annual Financials 2009		Management’s Discussion and Analysis (prepared in US$)

Report of Management

Management’s Responsibility for the Consolidated Financial Statements

The accompanying Consolidated Financial Statements of Cenovus Energy Inc. (“Cenovus”) are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in United States dollars in accordance with Canadian generally accepted accounting principles and include certain estimates that reflect Management’s best judgments.

The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of three independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes-Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets with Management and the independent auditors at least on a quarterly basis to review and approve interim Consolidated Financial Statements and Management’s Discussion and Analysis prior to their release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion and Analysis and recommend their approval to the Board of Directors.

Management’s Assessment of Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2009. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control–Integrated Framework to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at that date.

PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, was appointed to audit and provide independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at December 31, 2009 as stated in their Auditors’ Report. PricewaterhouseCoopers LLP has provided such opinions.


(signed)		(signed)

Brian C. Ferguson		Ivor M. Ruste
President &		Executive Vice-President &
Chief Executive Officer		Chief Financial Officer
Cenovus Energy Inc.		Cenovus Energy Inc.

February 17, 2010



Cenovus Energy Inc.		40
Annual Financials 2009		Report of Management

Independent Auditors’ Report

To the Shareholders of Cenovus Energy Inc.

We have completed integrated audits of Cenovus Energy Inc.’s 2009 and 2008 consolidated financial statements and of its internal control over financial reporting as of December 31, 2009 and an audit of its 2007 consolidated financial statements. Our opinions, based on our audits, are presented below.

Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Cenovus Energy Inc. as at December 31, 2009 and December 31, 2008, and the related consolidated statements of earnings and comprehensive income, shareholders’ equity, and cash flows for each of the years in the three year period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits of the Company’s financial statements as at December 31, 2009 and December 31, 2008 and for each of the years in the two year period ended December 31, 2009 in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). We conducted our audit of the Company’s financial statements for the year ended December 31, 2007 in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as at December 31, 2009 and December 31, 2008 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2009 in accordance with Canadian generally accepted accounting principles.

Internal Control over Financial Reporting

We have also audited Cenovus Energy Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.



Cenovus Energy Inc.		41
Annual Financials 2009		Independent Auditors’ Report

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009 based on criteria established in Internal Control — Integrated Framework issued by the COSO.

(signed)

PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
Canada

February 17, 2010



Cenovus Energy Inc.		42
Annual Financials 2009		Independent Auditors’ Report

CONSOLIDATED STATEMENT OF EARNINGS AND COMPREHENSIVE INCOME


For the years ended December 31, (US$ millions, except per share amounts)		2009			2008			2007

Revenues, Net of Royalties	(Note 1)		10,140			16,559			13,406
Expenses	(Note 1)
Production and mineral taxes			38			75			63
Transportation and selling			672			963			756
Operating			1,154			1,223			1,114
Purchased product			5,250			9,710			7,476
Depreciation, depletion and amortization			1,343			1,318			1,426
General and administrative			188			167			145
Interest, net	(Note 6)		218			218			187
Accretion of asset retirement obligation	(Note 14)		39			39			28
Foreign exchange (gain) loss, net	(Note 7)		290			(250	)		380
Other (income) loss, net			(2	)		3			4

			9,190			13,466			11,579
Earnings Before Income Tax			950			3,093			1,827
Income tax expense	(Note 8)		302			725			423

Net Earnings			648			2,368			1,404
Other Comprehensive Income, Net of Tax
Foreign Currency Translation Adjustment			1,979			(2,246	)		1,265

Comprehensive Income			2,627			122			2,669


Net Earnings per Common Share	(Note 19)
Basic			0.86			3.16			1.86

Diluted			0.86			3.15			1.84

See accompanying Notes to Consolidated Financial Statements.



Cenovus Energy Inc.		43
Annual Financials 2009		Consolidated Financial Statements (prepared in US$)

CONSOLIDATED BALANCE SHEET


As at December 31, (US$ millions)		2009		2008

Assets
Current Assets
Cash and cash equivalents			148		153
Accounts receivable and accrued revenues			874		598
Income tax receivable			38		—
Current portion of Partnership Contribution Receivable	(Note 9)		330		313
Risk management	(Note 18)		58		681
Inventories	(Note 10)		836		503

			2,284		2,248
Property, Plant and Equipment, net	(Notes 1, 11)		14,537		12,260
Partnership Contribution Receivable	(Note 9)		2,504		2,834
Risk Management	(Note 18)		1		38
Other Assets	(Note 12)		131		150
Goodwill	(Note 1)		1,095		936

			20,552		18,466


Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities			1,444		1,114
Income tax payable			—		254
Current portion of Partnership Contribution Payable	(Note 9)		325		306
Risk management	(Note 18)		67		40
Current portion of long-term debt	(Note 13)		—		84

			1,836		1,798
Long-Term Debt	(Note 13)		3,493		2,952
Partnership Contribution Payable	(Note 9)		2,532		2,857
Risk Management	(Note 18)		4		—
Asset Retirement Obligation	(Note 14)		1,096		648
Other Liabilities			54		52
Future Income Taxes	(Note 8)		2,357		2,411

			11,372		10,718

Commitments and Contingencies	(Note 20)
Shareholders’ Equity	(Note 15)		9,180		7,748

			20,552		18,466

See accompanying Notes to Consolidated Financial Statements.

Approved by the Board


(signed)		(signed)

Michael A. Grandin		Patrick D. Daniel
Director		Director
Cenovus Energy Inc.		Cenovus Energy Inc.



Cenovus Energy Inc.		44
Annual Financials 2009		Consolidated Financial Statements (prepared in US$)

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY


	Share		Paid in								Owner’s
	Capital		Surplus			Retained					Net
(US$ millions)	(Note 15)		(Note 15)			Earnings		AOCI*			Investment			Total

Balance as of December 31, 2006		—		—			—		1,169			6,145			7,314
Net earnings		—		—			—		—			1,404			1,404
Net distribution to owner		—		—			—		—			(1,976	)		(1,976	)
Other comprehensive income (loss)		—		—			—		1,265			—			1,265

Balance as of December 31, 2007		—		—			—		2,434			5,573			8,007
Net earnings		—		—			—		—			2,368			2,368
Net distribution to owner		—		—			—		—			(381	)		(381	)
Other comprehensive income (loss)		—		—			—		(2,246	)		—			(2,246	)

Balance as of December 31, 2008		—		—			—		188			7,560			7,748
Net earnings		—		—			—		—			609			609
Net distribution to owner		—		—			—		—			(1,045	)		(1,045	)
Other comprehensive income (loss)		—		—			—		1,908			—			1,908

Owner’s Net Investment at Arrangement date — November 30, 2009		—		—			—		2,096			7,124			9,220
Issuance of common stock in connection with the Arrangement		2,222		—			—		—			(2,222	)		—
Reclassification of owner’s net investment to paid in surplus in connection with the Arrangement		—		4,902			—		—			(4,902	)		—
Net earnings — December 1 to December 31		—		—			39		—			—			39
Dividends on common shares		—		(151	)		—		—			—			(151	)
Common shares issued under option plans		1		—			—		—			—			1
Other comprehensive income (loss)		—		—			—		71			—			71

Balance as of December 31, 2009		2,223		4,751			39		2,167			—			9,180


*		Accumulated Other Comprehensive Income

See accompanying Notes to Consolidated Financial Statements.



Cenovus Energy Inc.		45
Annual Financials 2009		Consolidated Financial Statements (prepared in US$)

CONSOLIDATED STATEMENT OF CASH FLOWS


For the years ended December 31, (US$ millions)		2009			2008			2007

Operating Activities
Net earnings			648			2,368			1,404
Depreciation, depletion and amortization			1,343			1,318			1,426
Future income taxes	(Note 8)		(551	)		385			(182	)
Unrealized (gain) loss on risk management	(Note 18)		667			(734	)		348
Unrealized foreign exchange (gain) loss			313			(259	)		383
Accretion of asset retirement obligation	(Note 14)		39			39			28
Other			13			(29	)		129
Net change in other assets and liabilities			(23	)		(89	)		(48	)
Net change in non-cash working capital			1,047			(312	)		(474	)

Cash From Operating Activities			3,496			2,687			3,014


Investing Activities
Capital expenditures	(Note 1)		(1,895	)		(2,046	)		(1,489	)
Proceeds from divestitures	(Note 5)		209			47			—
Net change in other assets			(18	)		(48	)		(34	)
Net change in non-cash working capital			(76	)		83			(10	)

Cash (Used in) Investing Activities			(1,780	)		(1,964	)		(1,533	)


Net Cash Provided before Financing Activities			1,716			723			1,481


Financing Activities
Net issuance (repayment) of revolving long-term debt			(304	)		(503	)		(148	)
Issuance of long-term debt			173			268			931
Repayment of long-term debt			(88	)		(236	)		(99	)
Issuance of U.S. Unsecured Notes	(Note 13)		3,468			—			—
Payment of note payable to EnCana	(Note 13)		(3,500	)		—			—
Payment of transition account payable to EnCana			(250	)		—			—
Net financing transactions with EnCana			(1,045	)		(381	)		(1,976	)
Issuance of common shares			1			—			—
Dividends on common shares			(151	)		—			—
Other			(34	)		—			—

Cash (Used in) Financing Activities			(1,730	)		(852	)		(1,292	)


Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency			9			(20	)		7

Increase (Decrease) in Cash and Cash Equivalents			(5	)		(149	)		196
Cash and Cash Equivalents, Beginning of Year			153			302			106

Cash and Cash Equivalents, End of Year			148			153			302


Supplemental Cash Flow Information	(Note 19)

See accompanying Notes to Consolidated Financial Statements.



Cenovus Energy Inc.		46
Annual Financials 2009		Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc. (“Cenovus” or the “Company”) is in the business of the development, production and marketing of bitumen, crude oil, natural gas and natural gas liquids (“NGLs”) in Canada with refining operations in the United States.

The Company is headquartered in Calgary, Alberta and its common shares are listed on the Toronto and New York stock exchanges. Information on the Company’s background and the basis of presentation for these financial statements are found in Note 2.

Cenovus is organized into two operating divisions:

•

For financial statement reporting purposes, our operating and reportable segments are:

•

Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory.

The operating and reportable segments shown above have been changed from those presented in prior periods to match Cenovus’s structure. All prior periods have been restated to reflect this presentation.

The tabular financial information which follows presents the segmented information first by segment and geographic location, then by product and operating division. Capital expenditures, goodwill, sales information and information relating to Cenovus’s major customers are summarized at the end of the note.



Cenovus Energy Inc.		47
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Results of Operations

Segment and Geographic Information


	Upstream Canada						Downstream Refining
For the years ended December 31, (US$ millions)	2009		2008		2007		2009		2008			2007

Revenues, Net of Royalties		5,598		6,972		6,528		5,280		9,011			7,315
Expenses
Production and mineral taxes		38		75		63		—		—			—
Transportation and selling		672		963		756		—		—			—
Operating		671		742		688		453		492			428
Purchased product		832		1,101		1,751		4,517		8,760			5,813

Operating cash flow		3,385		4,091		3,270		310		(241	)		1,074
Depreciation, depletion and amortization		1,101		1,107		1,222		192		188			159

Segment Income (Loss)		2,284		2,984		2,048		118		(429	)		915


Property, Plant & Equipment		9,660		8,148		9,574		4,767		4,032			3,706


Goodwill		1,095		936		1,159		—		—			—


Total Assets		14,481		12,863		15,569		5,660		4,637			4,887


	Corporate and Eliminations									Consolidated
For the years ended December 31, (US$ millions)	2009			2008			2007			2009			2008			2007

Revenues, Net of Royalties		(738	)		576			(437	)		10,140			16,559			13,406
Expenses
Production and mineral taxes		—			—			—			38			75			63
Transportation and selling		—			—			—			672			963			756
Operating		30			(11	)		(2	)		1,154			1,223			1,114
Purchased product		(99	)		(151	)		(88	)		5,250			9,710			7,476

		(669	)		738			(347	)		3,026			4,588			3,997
Depreciation, depletion and amortization		50			23			45			1,343			1,318			1,426

Segment Income (Loss)		(719	)		715			(392	)		1,683			3,270			2,571

General and Administrative		188			167			145			188			167			145
Interest, net		218			218			187			218			218			187
Accretion of asset retirement obligation		39			39			28			39			39			28
Foreign exchange (gain) loss, net		290			(250	)		380			290			(250	)		380
Other (income) loss, net		(2	)		3			4			(2	)		3			4

		733			177			744			733			177			744

Earnings Before Income Tax											950			3,093			1,827
Income tax expense											302			725			423

Net Earnings (Loss)											648			2,368			1,404


Property, Plant & Equipment		110			80			104			14,537			12,260			13,384


Goodwill		—			—			—			1,095			936			1,159


Total Assets		411			966			531			20,552			18,466			20,987



Cenovus Energy Inc.		48
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Upstream Canada Product and Divisional Information


	Crude Oil & NGLs
(US$ millions)	Integrated Oil						Canadian Plains						Total
For the years ended December 31,	2009		2008		2007		2009		2008		2007		2009		2008		2007

Revenues, Net of Royalties		1,202		1,117		738		1,373		2,106		1,453		2,575		3,223		2,191
Expenses
Production and mineral taxes		—		—		—		24		38		29		24		38		29
Transportation and selling		430		526		366		179		321		263		609		847		629
Operating		176		170		159		229		239		215		405		409		374
Purchased product		—		—		—		—		—		—		—		—		—


Operating Cash Flow		596		421		213		941		1,508		946		1,537		1,929		1,159


	Natural Gas
(US$ millions)	Integrated Oil						Canadian Plains						Total
For the years ended December 31,	2009		2008		2007		2009		2008		2007		2009		2008		2007

Revenues, Net of Royalties		180		192		252		1,902		2,301		2,186		2,082		2,493		2,438
Expenses
Production and mineral taxes		—		—		—		13		36		34		13		36		34
Transportation and selling		2		7		12		39		71		82		41		78		94
Operating		20		39		40		210		241		221		230		280		261
Purchased product		—		—		—		—		—		—		—		—		—


Operating Cash Flow		158		146		200		1,640		1,953		1,849		1,798		2,099		2,049


	Other
(US$ millions)	Integrated Oil						Canadian Plains						Total
For the years ended December 31,	2009		2008		2007		2009		2008		2007		2009		2008		2007

Revenues, Net of Royalties		73		119		75		868		1,137		1,824		941		1,256		1,899
Expenses
Production and mineral taxes		1		1		—		—		—		—		1		1		—
Transportation and selling		22		38		23		—		—		10		22		38		33
Operating		18		31		30		18		22		23		36		53		53
Purchased product		—		—		—		832		1,101		1,751		832		1,101		1,751


Operating Cash Flow		32		49		22		18		14		40		50		63		62


	Total Upstream Canada
(US$ millions)	Integrated Oil						Canadian Plains						Total
For the years ended December 31,	2009		2008		2007		2009		2008		2007		2009		2008		2007

Revenues, Net of Royalties		1,455		1,428		1,065		4,143		5,544		5,463		5,598		6,972		6,528
Expenses
Production and mineral taxes		1		1		—		37		74		63		38		75		63
Transportation and selling		454		571		401		218		392		355		672		963		756
Operating		214		240		229		457		502		459		671		742		688
Purchased product		—		—		—		832		1,101		1,751		832		1,101		1,751


Operating Cash Flow		786		616		435		2,599		3,475		2,835		3,385		4,091		3,270



Cenovus Energy Inc.		49
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Capital Expenditures


For the years ended December 31, (US$ millions)	2009		2008		2007

Integrated Oil		476		644		450
Canadian Plains		478		872		795

Upstream Canada		954		1,516		1,245
Downstream Refining		907		478		220
Corporate		31		52		10

		1,892		2,046		1,475

Acquisition Capital
Integrated Oil		—		—		14
Canadian Plains		3		—		—


Total		1,895		2,046		1,489

In addition to the above, in 2009 we acquired strategic bitumen lands in exchange for certain non-core holdings.

Goodwill Additions

There were no additions to goodwill during 2009, 2008 or 2007; changes in the goodwill balance result from changes in foreign exchange rates.

Export Sales

Sales of crude oil, natural gas and NGLs produced or purchased in Canada delivered to customers outside of Canada were $544 million (2008-$1,296 million; 2007-$943 million).

Major Customers

In connection with the marketing and sale of Cenovus’s own and purchased crude oil, natural gas and refined products for the year ended December 31, 2009, Cenovus had two customers (2008-two; 2007-two) which individually accounted for more than 10 percent of its consolidated revenues, net of royalties. Sales to these customers, major international integrated energy companies with an investment grade credit rating, were approximately $5,658 million (2008-$8,979 million; 2007-$6,916 million).

2. BACKGROUND & BASIS OF PRESENTATION

Cenovus was created on November 30, 2009 and began independent operations on December 1, 2009, as a result of the Arrangement involving EnCana Corporation (“EnCana”) whereby EnCana was split into two independent energy companies, one a natural gas company, EnCana and the other an integrated oil company, Cenovus. In connection with the Arrangement, EnCana common shareholders received one share in each of the new EnCana and Cenovus in exchange for each EnCana share held. Common shares of Cenovus began trading on a “when issued” basis on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges on November 2, 2009. Regular trading of the Cenovus shares began on the TSX on December 3, 2009 and on the NYSE on December 9, 2009.

Cenovus has entered into various transitional agreements with EnCana for the use of certain technical services, the marketing of crude oil, natural gas and NGLs and office space lease arrangements. These agreements reflect terms negotiated in anticipation of each company being stand-alone public companies, each with independent boards of directors and management teams.



Cenovus Energy Inc.		50
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

2. BACKGROUND & BASIS OF PRESENTATION (continued)

Accordingly, up until the completion of the Arrangement, EnCana was considered a related party due to its parent-subsidiary relationship with the Cenovus entities. However, subsequent to the Arrangement, EnCana is no longer a related party as defined by the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3840 — Related Party Transactions.

Basis of presentation / Carve-out financial information

The Consolidated Financial Statements for the year ended December 31, 2009 include the results for the period from January 1 to November 30, 2009 prior to the Arrangement with EnCana, in addition to the results for the period from December 1 to December 31, 2009 as described below. The consolidated financial results for the periods prior to December 1, 2009 represent the financial position, results of operations and cash flows of the businesses transferred to Cenovus on a carve-out basis.

The historical financial information prior to December 1, 2009 has been derived from the accounting records of EnCana using the historical results of operations and historical basis of assets and liabilities of the businesses transferred to Cenovus on a carve-out accounting basis.

As the Company operated as part of EnCana and was not a stand-alone entity prior to November 30, 2009, the historical Consolidated Financial Statements include allocations of certain EnCana revenues, expenses, assets and liabilities, including the items described below.

The operating results of Cenovus were specifically identified based on EnCana’s divisional organization. Certain other expenses presented in the Consolidated Statement of Earnings and Comprehensive Income represent allocations and estimates of the cost of services incurred by EnCana. These allocations and estimates include unrealized mark-to-market gains and losses, general and administrative costs, net interest, foreign exchange gains and losses and income tax expenses. The majority of the assets and liabilities of Cenovus have been identified based on the divisional structure, with the most significant exceptions being property, plant and equipment (“PP&E”), income taxes payable and long-term debt.

Downstream refining, crude oil and natural gas marketing and corporate depreciation, depletion and amortization have been specifically identified based on EnCana’s existing divisional structure where possible. Depletion related to upstream properties has been allocated to Cenovus based on the related production volumes utilizing the depletion rate calculated for EnCana’s consolidated Canadian cost centre.

Mark-to-market gains and losses resulting from derivative financial instruments entered into by EnCana have been allocated to Cenovus based on the related product volumes.

Salaries, benefits, pension, long-term incentives and other post-employment benefits costs, assets and liabilities have been allocated to Cenovus based on Management’s best estimate of how services were historically provided by existing employees. Costs, assets and liabilities associated with retired employees remain with EnCana.

Net interest expense has been calculated primarily using the debt balance allocated to Cenovus.

Income taxes have been recorded as if Cenovus and its subsidiaries had been separate tax paying legal entities, each filing a separate tax return in its local jurisdiction. The calculation of income taxes is based on a number of assumptions, allocations and estimates, including those used to prepare the Cenovus Carve-out Consolidated Financial Statements. Prior to the Arrangement, Cenovus’s tax pools were allocated for the Canadian cost centre based on the fair value allocation of PP&E for carve-out purposes.



Cenovus Energy Inc.		51
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

2. BACKGROUND & BASIS OF PRESENTATION (continued)

PP&E related to upstream oil and gas activities are accounted for by Cenovus using the full cost method of accounting. PP&E related to upstream oil and gas activities has been determined based on an allocation process which used the ratio of future net revenue, discounted at 10 percent, of the respective divisions to the future net revenue, discounted at 10 percent, of all proved properties in Canada at December 31, 2008 and December 31, 2007, respectively. Future net revenue is the estimated net amount to be received with respect to development and production of crude oil and natural gas reserves.

Goodwill has been allocated to Cenovus based on the properties associated with the former business combinations on which it arose.

For the purpose of preparing the Carve-out Consolidated Financial Statements, it was determined that Cenovus should maintain approximately the same Debt to Capitalization ratio as consolidated EnCana. As a result, prior to the Arrangement, debt was allocated to Cenovus based on this ratio. Debt is defined as the current and long-term portions of Long-term Debt. Capitalization is not a term that has a prescribed meaning under generally accepted accounting principles (“non-GAAP”) and is a measure defined as Debt plus Shareholders’ Equity.

Management believes the assumptions underlying the Cenovus Carve-out Consolidated Financial Statements are reasonable. However, the Cenovus Consolidated Financial Statements herein may not reflect Cenovus’s financial position, results of operations, and cash flows had Cenovus been a stand-alone company during the periods presented or what Cenovus’s operations, financial position, and cash flows will be in the future. EnCana’s direct investment in Cenovus is shown as Net Investment in place of Shareholders’ Equity because a direct ownership by shareholders in Cenovus did not exist prior to November 30, 2009. EnCana’s investment includes the accumulated net earnings, other comprehensive income and net cash distributions to EnCana.

In the opinion of Management, the Consolidated and the historical Carve-out Consolidated Financial Statements reflect all adjustments (including normal recurring adjustments) necessary for a fair statement of the financial position and the results of operations and cash flows in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”).

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in United States (U.S.) dollars. While Cenovus’s reporting currency is U.S. dollars, the functional currency is Canadian dollars. All references to US$ or $ are to U.S. dollars and references to C$ are to Canadian dollars.

A) Principles of Consolidation

The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries and are presented in accordance with Canadian GAAP. Information prepared in accordance with GAAP in the United States is included in Note 21.

Investments in jointly controlled partnerships and unincorporated joint ventures carry on certain of Cenovus’s development, production and crude oil refining businesses and are accounted for using the proportionate consolidation method, whereby Cenovus’s proportionate share of revenues, expenses, assets and liabilities are included in the accounts.



Cenovus Energy Inc.		52
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

B) Foreign Currency Translation

The accounts of self-sustaining operations are translated using the current rate method, whereby assets and liabilities are translated at period end exchange rates, while revenues and expenses are translated using average rates over the period. Translation gains and losses relating to the self-sustaining operations are included in Accumulated Other Comprehensive Income (“AOCI”) as a separate component of Shareholders’ Equity. As at December 31, 2009, AOCI is comprised solely of foreign currency translation adjustments.

Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Earnings.

C) Measurement Uncertainty

The timely preparation of the Consolidated Financial Statements in conformity with Canadian GAAP requires that Management make estimates and assumptions and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

Amounts recorded for depreciation, depletion and amortization, asset retirement costs and obligations and amounts used for ceiling test and impairment calculations are based on estimates of crude oil and natural gas reserves and future costs required to develop those reserves. By their nature, these estimates of reserves, including the estimates of future prices and costs, and the related future cash flows are subject to measurement uncertainty, and the impact in the Consolidated Financial Statements of future periods could be material.

The values of pension assets and obligations and the amount of pension costs charged to net earnings depend on certain actuarial and economic assumptions which, by their nature, are subject to measurement uncertainty.

The amount of compensation expense accrued for long-term performance-based compensation arrangements is subject to Management’s best estimate of whether or not the performance criteria will be met and what the ultimate payout will be.

The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty.

Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus operates are subject to change. As such, income taxes are subject to measurement uncertainty.

D) Revenue Recognition

Revenues associated with the sales of Cenovus’s crude oil, natural gas, NGLs and petroleum and refined products are recognized when title passes from the Company to its customer. Realized gains and losses from crude oil and natural gas commodity price risk management activities are recorded in revenue when the product is sold.

Revenues and purchased product are recorded on a gross basis when the title to product passes and the risks and rewards of ownership have been transferred. Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with the services provided as agent are recorded as the services are provided.



Cenovus Energy Inc.		53
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Unrealized gains and losses from natural gas and crude oil commodity price risk management activities are recorded as revenue based on the related mark-to-market calculations at the end of the respective period.

E) Production and Mineral Taxes

Costs paid to non-mineral interest owners based on production of crude oil, natural gas and NGLs are recognized when the product is produced.

F) Transportation and Selling Costs

Costs paid for the transportation and selling of crude oil, natural gas and NGLs, including diluent, are recognized when the product is delivered and the services provided.

G) Employee Benefit Plans

Accruals for obligations under the employee benefit plans and the related costs are recorded net of plan assets.

Pension expense for the defined benefit pension plan includes the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of the net transitional obligation, the amortization of adjustments arising from pension plan amendments and the amortization of the excess of the net actuarial gain or loss over 10 percent of the greater of the benefit obligation and the fair value of plan assets. Amortization is done on a straight-line basis over a period covering the expected average remaining service lives of employees covered by the plans.

Pension expense for the defined contribution pension plans is recorded as the benefits are earned by the employees covered by the plans.

H) Income Taxes

Cenovus follows the liability method of accounting for income taxes, where future income taxes are recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs.



Cenovus Energy Inc.		54
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

I) Earnings Per Share Amounts

Basic net earnings per common share is computed by dividing the net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share amounts are calculated giving effect to the potential dilution that would occur if stock options, without tandem share appreciation rights attached, were exercised or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options without tandem share appreciation rights attached and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options without tandem share appreciation rights attached are used to repurchase common shares at the average market price.

J) Cash and Cash Equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased.

K) Inventories

Product inventories, including petroleum and refined products, are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis.

L) Property, Plant and Equipment

Upstream Canada

Crude oil and natural gas properties are accounted for in accordance with the CICA guideline on full cost accounting in the oil and gas industry. Under this method, all costs, including internal costs and asset retirement costs, directly associated with the acquisition of, the exploration for, and the development of bitumen, crude oil and natural gas reserves, are capitalized on a country-by-country cost centre basis.

Costs accumulated within each cost centre are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves determined using estimated future prices and costs. For purposes of this calculation, natural gas is converted to oil on an energy equivalent basis. Capitalized costs subject to depletion include estimated future costs to be incurred in developing proved reserves. Proceeds from the divestiture of properties are normally deducted from the full cost pool without recognition of gain or loss unless that deduction would result in a change to the rate of depreciation, depletion and amortization of 20 percent or greater, in which case a gain or loss is recorded. Costs of major development projects and costs of acquiring and evaluating significant unproved properties are excluded, on a cost centre basis, from the costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties, or impairment has occurred. Costs that have been impaired are included in the costs subject to depreciation, depletion and amortization.

An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to the amount by which the carrying amount exceeds the sum of:

i. the fair value of proved and probable reserves; and

ii. the costs of unproved properties that have been subject to a separate impairment test.



Cenovus Energy Inc.		55
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Downstream Refining

The initial acquisition costs of refinery property, plant and equipment are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use and the associated asset retirement costs. Capitalized costs are not subject to depreciation until the asset is put into use, after which they are depreciated on a straight-line basis over the estimated service lives of each component of the downstream facilities.

An impairment loss is recognized on refinery property, plant and equipment when the carrying amount is not recoverable and exceeds its fair value. The carrying amount is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from expected use and eventual disposition. If the carrying amount is not recoverable, an impairment loss is measured as the amount by which the refinery asset exceeds the fair value.

Other

Costs associated with office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 25 years. Assets under construction are not subject to depreciation until put into use.

M) Capitalization of Costs

Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred.

N) Amortization of Other Assets

Items included in Other Assets are amortized, where applicable, on a straight-line basis over the estimated useful lives of the assets.

O) Goodwill

Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment at least annually. Goodwill and all other assets and liabilities have been allocated to the country cost centre level, referred to as a reporting unit. To assess impairment, the fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit’s goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount.



Cenovus Energy Inc.		56
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

P) Asset Retirement Obligation

The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when incurred and a reasonable estimate of fair value can be made.

Asset retirement obligations include those legal obligations where Cenovus will be required to retire tangible long-lived assets such as producing well sites, natural gas processing plants, and refining facilities. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost.

Amortization of asset retirement costs are included in depreciation, depletion and amortization in the Consolidated Statement of Earnings. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statement of Earnings.

Actual expenditures incurred are charged against the accumulated obligation.

Q) Stock-Based Compensation

Obligations for payments, cash or common shares, under Cenovus’s stock options with tandem share appreciation rights attached, share appreciation rights and deferred share units plans are accrued using the intrinsic method as compensation cost over the vesting period. Fluctuations in the price of Cenovus’s common shares change the accrued compensation cost and are recognized when they occur.

EnCana replacement share options with tandem share appreciation rights attached and share appreciation rights held by Cenovus employees are accrued using the fair value method. The fair value is recognized as compensation cost over the vesting period. Fluctuations in the fair value of the rights change the accrued compensation cost and are recognized when they occur.

R) Financial Instruments

Financial instruments are measured at fair value on initial recognition of the instrument, except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as “held-for-trading”, “available-for-sale”, “held-to-maturity”, “loans and receivables”, or “other financial liabilities” as defined by the accounting standard.

Financial assets and financial liabilities “held-for-trading” are measured at fair value with changes in those fair values recognized in net earnings. Financial assets “available-for-sale” are measured at fair value, with changes in those fair values recognized in Other Comprehensive Income (“OCI”). Financial assets “held-to-maturity”, “loans and receivables” and “other financial liabilities” are measured at amortized cost using the effective interest method of amortization.

Cash and cash equivalents are designated as “held-for-trading” and are measured at fair value. Accounts receivable and accrued revenues and the Partnership Contribution Receivable are designated as “loans and receivables”. Accounts payable and accrued liabilities, the Partnership Contribution Payable and long-term debt are designated as “other financial liabilities”. Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt and amortized using the effective interest method.



Cenovus Energy Inc.		57
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Derivative Financial Instruments

Risk management assets and liabilities are derivative financial instruments classified as “held-for-trading” unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net earnings. Realized gains or losses from financial derivatives related to natural gas and crude oil commodity prices are recognized in natural gas and crude oil revenues as the related sales occur. Realized gains or losses from financial derivatives related to power commodity prices are recognized in operating costs as the related power costs are incurred. Unrealized gains and losses are recognized at the end of each respective reporting period. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.

Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Derivative financial instruments are not used for speculative purposes.

Policies and procedures are in place with respect to the required documentation and approvals for the use of derivative financial instruments and specifically ties their use, in the case of commodities, to the mitigation of market price risk associated with cash flows expected to be generated from budgeted capital programs, and in other cases to the mitigation of market price risks for specific assets and obligations. When applicable, the Company identifies relationships between financial instruments and anticipated transactions, as well as its risk management objective and the strategy for undertaking the economic hedge transaction. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.

S) Reclassification

Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2009.

T) Recent Accounting Pronouncements

In February 2008, the CICA’s Accounting Standards Board confirmed that International Financial Reporting Standards (“IFRS”) will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises. Cenovus will be required to report its results in accordance with IFRS beginning in 2011. Cenovus has developed a changeover plan to complete the transition to IFRS by January 1, 2011, including the preparation of required comparative information. The impact of IFRS on the Consolidated Financial Statements is not reasonably determinable at this time.

In addition, there are three recent accounting pronouncements as noted below, which Cenovus will be required to adopt as of January 1, 2011. All of these standards are converged with IFRS.

•

“Business Combinations”, Section 1582, which replaces the previous Business Combinations standard. The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the Statement of Earnings. The adoption of this standard will impact the accounting treatment of future business combinations.



Cenovus Energy Inc.		58
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

•

“Consolidated Financial Statements”, Section 1601, which together with Section 1602 below, replace the former consolidated financial statement standard. Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard should not have a material impact on Cenovus’s Consolidated Financial Statements.

•

“Non-controlling Interests”, Section 1602, which establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest to be classified as a separate component of equity. In addition, net earnings, and components of other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard should not have a material impact on the Consolidated Financial Statements.

4. CHANGES IN ACCOUNTING POLICIES AND PRACTICES

On January 1, 2009, Cenovus adopted the CICA Handbook Section “Goodwill and Intangible Assets”, Section 3064. The new standard replaces the previous goodwill and intangible asset standard and revises the requirement for recognition, measurement, presentation and disclosure of intangible assets. The adoption of this standard had no material impact on the Consolidated Financial Statements.

5. DIVESTITURES


For the years ended December 31, (US$ millions)	2009		2008		2007

Integrated Oil		83		8		—
Canadian Plains		123		39		—
Corporate		3		—		—

Canada		209		47		—

As part of on-going portfolio management efforts, in 2009 Cenovus received cash proceeds of $209 million related to the divestiture of certain oil and gas assets.

6. INTEREST, NET


For the years ended December 31, (US$ millions)	2009			2008			2007

Interest Expense-Long-Term Debt		187			194			185
Interest Expense-Other		194			213			225
Interest Income		(163	)		(189	)		(223	)

		218			218			187

Interest Expense-Other and Interest Income are primarily due to the Partnership Contribution Payable and Receivable, respectively (See Note 9).



Cenovus Energy Inc.		59
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

7. FOREIGN EXCHANGE (GAIN) LOSS, NET


For the years ended December 31, (US$ millions)	2009			2008			2007

Unrealized Foreign Exchange (Gain) Loss on:
Translation of U.S. dollar debt issued from Canada		(357	)		351			(268	)
Translation of U.S. dollar Partnership Contribution Receivable issued from Canada		478			(608	)		617
Other Foreign Exchange (Gain) Loss		169			7			31

		290			(250	)		380

Other foreign exchange (gain) loss in 2009 includes a $107 million unrealized loss on the translation of U.S. dollar risk management assets and liabilities (2008-unrealized gain of $2 million; 2007-unrealized loss of $34 million) and a $50 million realized loss related to the timing of receipt of the $3.5 billion debt offering proceeds from escrow (see Note 13).

8. INCOME TAXES

The provision for income taxes is as follows:


For the years ended December 31, (US$ millions)	2009			2008			2007

Current
Canada		896			362			432
United States		(43	)		(22	)		173

Total Current Tax		853			340			605
Future Tax		(551	)		385			(182	)

		302			725			423

The income tax provision in 2009 reflects the acceleration of the income tax impact of the dissolution of a partnership during the fourth quarter in conjunction with the Arrangement with EnCana.

Total income tax expense in 2009 was $302 million, which was $423 million lower than in 2008 due to lower earnings before income tax. Current income tax expense in 2009 was $853 million, compared to $340 million in 2008. The increase is largely attributable to the acceleration of income tax arising from the dissolution of EnCana’s Canadian oil and gas partnership in connection with the Arrangement and the realization of significant hedging gains in 2009. Current tax expense for the three years is primarily an allocation of EnCana’s income tax liability on a carve-out accounting basis and as a result, there is no income tax payable by Cenovus at the end of 2009. For 2009, there was a recovery of future income tax expense of $551 million compared to an expense of $385 million in 2008. The significant net recovery was due to the 2009 reversal of future tax on partnership income and unrealized mark-to-market hedging gains.



Cenovus Energy Inc.		60
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

8. INCOME TAXES (continued)

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:


For the years ended December 31, (US$ millions)	2009			2008			2007

Earnings Before Income Tax		950			3,093			1,827
Canadian Statutory Rate		29.2	%		29.7	%		32.3	%

Expected Income Tax		277			917			590
Effect on Taxes Resulting from:
Statutory and other rate differences		(4	)		(79	)		17
Effect of tax rate changes		—			—			(147	)
Effect of legislative changes		—			—			(76	)
Non-taxable downstream partnership (income) loss		6			6			(70	)
International financing		(118	)		(127	)		—
Foreign exchange (gains) losses not included in net earnings		67			11			—
Non-taxable capital (gains) losses		11			(50	)		45
Other		63			47			64

		302			725			423

Effective Tax Rate		31.8	%		23.4	%		23.2	%

The net future income tax liability is comprised of:


As at December 31, (US$ millions)	2009			2008

Future Tax Liabilities
Property, plant and equipment in excess of tax values		2,535			1,810
Timing of partnership items		9			470
Risk management		16			185
Other		59			—
Future Tax Assets
Non-capital and net capital losses carried forward		(231	)		(19	)
Risk management		(31	)		—
Other		—			(35	)

Net Future Income Tax Liability		2,357			2,411

The approximate amounts of tax pools available are as follows:


As at December 31, (US$ millions)	2009		2008

Canada		3,543		4,092
United States		2,489		1,805

		6,032		5,897

Included in the above tax pools are $731 million (2008-$77 million) related to non-capital and net operating losses available for carry forward to reduce taxable income in future years. These losses expire no earlier than 2028.



Cenovus Energy Inc.		61
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

9. PARTNERSHIP CONTRIBUTION RECEIVABLE AND PAYABLE

In connection with the Arrangement with EnCana, Cenovus acquired EnCana’s assets which are jointly controlled with ConocoPhillips. On January 2, 2007, EnCana became a 50 percent partner in an integrated, North American oil business with ConocoPhillips which consists of an upstream entity and a downstream entity. The upstream entity contribution included assets from EnCana, primarily the Foster Creek and Christina Lake properties, with a fair value of $7.5 billion and a note receivable (Partnership Contribution Receivable) contributed from ConocoPhillips of an equal amount. For the downstream entity, ConocoPhillips contributed its Wood River and Borger refineries, located in Illinois and Texas, respectively, for a fair value of $7.5 billion and EnCana contributed a note payable (Partnership Contribution Payable) of $7.5 billion.

In accordance with Canadian GAAP, these entities have been accounted for using the proportionate consolidation method with the results of operations included in the Integrated Oil Division (See Note 1).

Partnership Contribution Receivable

This note receivable bears interest at a rate of 5.3 percent per annum. Equal payments of principal and interest are payable quarterly, with final payment due January 2, 2017. The current and long-term Partnership Contribution Receivable shown in the Consolidated Balance Sheet represents Cenovus’s 50 percent share of this promissory note, net of payments to date.

Mandatory Receipts


(US$ millions)	2010		2011		2012		2013		2014		Thereafter		Total

Partnership Contribution Receivable		330		347		366		386		407		998		2,834

Partnership Contribution Payable

This note payable bears interest at a rate of 6.0 percent per annum. Equal payments of principal and interest are payable quarterly, with final payment due January 2, 2017. The current and long-term Partnership Contribution Payable amounts shown in the Consolidated Balance Sheet represents Cenovus’s 50 percent share of this promissory note, net of payments to date.

Mandatory Payments


(US$ millions)	2010		2011		2012		2013		2014		Thereafter		Total

Partnership Contribution Payable		325		345		366		388		412		1,021		2,857

10. INVENTORIES


As at December 31, (US$ millions)	2009		2008

Product
Upstream Canada		255		165
Downstream Refining		563		323
Parts and Supplies		18		15

		836		503



Cenovus Energy Inc.		62
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

10. INVENTORIES (continued)

As a result of a significant decline in commodity prices in the latter half of 2008, Cenovus recorded a write-down of its product inventory by $152 million from cost to net realizable value. At December 31, 2009, the product turnover during the current year and the improvement in commodity prices resulted in a reversal of the prior year’s write-down of $144 million.

The total amount of inventories recognized as an expense during the year was $4,442 million (2008-$8,749 million; 2007-$5,752 million).

11. PROPERTY, PLANT AND EQUIPMENT, NET


	2009							2008
			Accumulated							Accumulated
As at December 31, (US$ millions)	Cost		DD&A*			Net		Cost		DD&A*			Net

Upstream Canada		20,626		(10,966	)		9,660		16,638		(8,490	)		8,148
Downstream Refining		5,256		(489	)		4,767		4,347		(315	)		4,032
Corporate and Eliminations		373		(263	)		110		190		(110	)		80

		26,255		(11,718	)		14,537		21,175		(8,915	)		12,260


*		Depreciation, depletion and amortization

Upstream Canada property, plant and equipment includes internal costs directly related to exploration, development and construction activities of $103 million (2008-$96 million). Costs classified as general and administrative expenses have not been capitalized as part of the capital expenditures.

Costs in respect of significant unproved properties and major development projects are excluded from the country cost centre’s depletable base. Downstream Refining assets not put into use are excluded from depreciable costs. At the end of the year these costs were:


As at December 31, (US$ millions)	2009		2008		2007

Upstream Canada		615		227		223
Downstream Refining		1,305		488		139

		1,920		715		362

The Canadian prices used in the ceiling test evaluation of Cenovus’s crude oil and natural gas reserves at December 31, 2009 were:


											Cumulative
											% Change
	2010		2011		2012		2013		2014		to 2021

Crude Oil (C$/barrel)		59.82		62.61		65.57		60.79		59.93		(10	)%
Natural Gas Liquids (C$/barrel)		65.72		65.93		66.14		67.03		66.32		1	%
Natural Gas (C$/Mcf)		5.31		6.21		6.09		5.88		5.86		—	%

12. OTHER ASSETS


As at December 31, (US$ millions)	2009		2008

Deferred Asset-Downstream Refining		116		134
Deferred Pension Plan and Savings Plan		9		8
Other		6		8

		131		150



Cenovus Energy Inc.		63
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

13. LONG-TERM DEBT


As at December 31, (US$ millions)	Note	2009			2008

Canadian Dollar Denominated Debt
Bank credit facilities	A		31

U.S. Dollar Denominated Debt
Bank credit facilities	A		25
Unsecured notes	B		3,500

			3,525

Total Debt Principal			3,556

Debt Discounts and Transaction Costs	C		(63	)
Current Portion of Long-Term Debt	D		—

			3,493			2,952

Long-term debt at December 31, 2008 represents an allocation of Cenovus’s proportionate share of EnCana’s consolidated debt as at December 31, 2008. Long-term debt was allocated to Cenovus on the same proportion of Canadian and U.S. dollar denominated debt and with the same terms and conditions as EnCana’s long-term debt. The effective average interest rate for long-term debt in 2009 was 5.7 percent (2008-5.5 percent).

A) Bank Credit Facilities

At December 31, 2009, Cenovus had in place an unsecured credit facility in the amount of C$2.5 billion or its equivalent amount in U.S. dollars. The revolving syndicated credit facility consists of two tranches, a C$2.0 billion 3-year tranche and a C$500 million 364-day tranche. The 3-year tranche matures in November 2012 and is extendible from time to time for a period of up to three years at the option of Cenovus and upon agreement from the lenders. The 364-day tranche matures in November 2010 and is extendible from time to time for a period of up to 364 days at the option of Cenovus and upon agreement from the lenders. If the facilities are not extended, the full amount of the outstanding principal will come due on the respective maturity dates.

Borrowings under both tranches are available by way of Bankers Acceptances, LIBOR based loans, prime rate loans or U.S. base rate loans. Bank credit outstanding at December 31, 2009 was drawn on the 3-year tranche and included prime rate and LIBOR based loans of $56 million.

B) U.S. Unsecured Notes

On September 18, 2009, a predecessor entity of Cenovus completed a private offering of senior unsecured notes for an aggregate principal amount of $3.5 billion, issued in three tranches, which are exempt from the registration requirements of the U.S. Securities Act of 1933 under Rule 144A and Regulation S. The net proceeds of the private offering along with $151 million deposited by the Company were placed into an escrow account pending the completion of the Arrangement with EnCana. Upon completion of the Arrangement, funds were released from escrow and the proceeds of the notes were then used to pay the note payable to EnCana of $3.5 billion as part of the Arrangement. On November 30, 2009, these notes became the direct, unsecured obligations of Cenovus.


(US$ millions)	2009

4.50% due September 15, 2014		800
5.70% due October 15, 2019		1,300
6.75% due November 15, 2039		1,400

		3,500



Cenovus Energy Inc.		64
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

13. LONG-TERM DEBT (continued)

Cenovus has agreed to use its commercially reasonable efforts to cause a registration statement with respect to an offer to exchange the U.S. unsecured notes for a new issue of notes registered under the U.S. Securities Act to be declared effective no later than September 18, 2010.

At December 31, 2009, the Company is in compliance with all of the terms of its debt agreements.

C) Debt Discounts and Transaction Costs

During 2009, $67 million in transaction costs and discounts were recorded within long-term debt relating to the issuance of the U.S. unsecured notes and the placement of the bank credit facilities. The costs are being amortized using the effective interest method. For comparative purposes, the transaction costs and discounts allocated to Cenovus for 2008 were $2 million.

D) Mandatory Debt Payments


	C$ Principal		US$ Principal		Total US$
($ millions)	Amount		Amount		Equivalent

2010		—		—		—
2011		—		—		—
2012		32		25		56
2013		—		—		—
2014		—		800		800
Thereafter		—		2,700		2,700

		32		3,525		3,556

14. ASSET RETIREMENT OBLIGATION

The aggregate carrying amount of the obligation associated with the retirement of upstream oil and gas assets and downstream refining facilities is as follows:


As at December 31, (US$ millions)	2009			2008

Asset Retirement Obligation, Beginning of Year		648			703
Liabilities Incurred		5			20
Liabilities Settled		(33	)		(49	)
Liabilities Divested		(9	)		(1	)
Change in Estimated Future Cash Flows		342			69
Accretion Expense		39			39
Foreign Currency Translation		104			(133	)

Asset Retirement Obligation, End of Year		1,096			648

The change estimated future cash flows in 2009 is due to the increased estimate of costs to be incurred and the rate of discount used for the current year estimate. The total undiscounted amount of estimated cash flows required to settle the obligation is $5,430 million (2008-$3,189 million), which has been discounted using a weighted average credit-adjusted risk free rate of 6.23 percent (2008-6.76 percent). Most of these obligations are not expected to be paid for several years, or decades, in the future and will be funded from general resources at that time.



Cenovus Energy Inc.		65
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

15. SHARE CAPITAL

Authorized

Cenovus is authorized to issue an unlimited number of Common Shares, an unlimited number of First Preferred Shares and an unlimited number of Second Preferred Shares.

Issued and Outstanding

Under the terms of the Arrangement described in Note 2, EnCana shareholders exchanged their EnCana share for one new EnCana Common Share and one Cenovus Common Share.


	Number of
	Common
	Shares		Amount
As at December 31, 2009	(millions)		($ millions)

Common Shares Issued Pursuant to the Arrangement		751.3		2,222
Common Shares Issued under Option Plans		—		1

Outstanding, End of Year		751.3		2,223

To determine Cenovus’s share capital amount, EnCana’s stated capital immediately prior to the Arrangement was split based on the relative fair market values of the EnCana and Cenovus Common Shares at the time of the initial exchange. Cenovus’s share capital amount was deducted from EnCana’s net investment with the remaining $4,902 million reclassified as Paid in Surplus. In December, Cenovus declared its share of a pre-Arrangement dividend of $0.20 per share, which was charged to Paid in Surplus. This dividend reflects an amount determined in connection with the Arrangement based on carve-out earnings and cash flows.

Under carve-out accounting, Owner’s Net Investment represents the accumulated net earnings of the operations and the accumulated net distributions to EnCana. Accumulated Other Comprehensive Income (“AOCI”) includes accumulated foreign currency translation adjustments. At the date of the Arrangement, EnCana’s net investment in Cenovus was $7,124 million.

At December 31, 2009, there were 24 million Common Shares available for future issuance under stock option plans. There were no Preferred Shares outstanding as at December 31, 2009.

Net Investment

EnCana’s net investment in the operations of Cenovus prior to the Arrangement is presented as total Net Investment in the Consolidated Financial Statements. Total Net Investment consists of Owner’s Net Investment and AOCI.

Option Plans

Options granted under the plans are generally fully exercisable after three years and expire five years after the date granted.



Cenovus Energy Inc.		66
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

15. SHARE CAPITAL (continued)

Cenovus Employee Stock Option Plan

Cenovus has stock-based compensation plans that allow employees to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, and are fully exercisable after three years and expire five years after the original grant date. Options granted under predecessor and/or related company replacement plans expire up to 10 years from the date the options were granted. In addition, certain stock options granted are performance based. The performance based stock options vest and expire under the same terms and service conditions as the underlying option, and vesting is subject to Cenovus attaining prescribed performance relative to pre-determined key measures. All new options issued by the Company have an associated Tandem Share Appreciation Right (“TSAR”) attached to them (see Note 17).

Cenovus Replacement Tandem Share Appreciation Rights (“Cenovus Replacement TSARs”) Held By EnCana Employees

Under the terms of the Arrangement, each original EnCana TSAR was replaced with one EnCana Replacement TSAR and one Cenovus Replacement TSAR with terms and conditions similar to the original EnCana TSAR. EnCana is required to reimburse Cenovus in respect of cash payments made by Cenovus to EnCana’s employees when these employees exercise a Cenovus Replacement TSAR and therefore, no compensation expense is recognized. No further Cenovus Replacement TSARs will be granted to EnCana employees.

EnCana employees can choose to exercise the Cenovus Replacement TSAR in exchange for a Cenovus common share or for cash. Cenovus has recorded a liability in the Consolidated Balance Sheet for Cenovus Replacement TSARs held by EnCana employees using the fair value method, with an offsetting account receivable from EnCana. The fair value of each Cenovus Replacement TSAR held by EnCana employees was estimated using the Black-Scholes-Merton model with weighted average assumptions as follows:


	2009

Risk Free Rate		1.46	%
Dividend Yield		3.16	%
Volatility		34.18	%
Cenovus’s Closing Common Share Price at December 31, 2009	C$	26.50

The following tables summarize information related to the Cenovus Replacement TSARs held by EnCana employees:

Weighted

Average

Total Number of

Performance

Exercise

As at December 31, 2009

TSARs

Price (C$)

Replacement TSARs — Pursuant to the Arrangement

23,047,704

10,491,119

27.14

Exercised — SARs

(29,840

)

—

18.57

Exercised — Options

(1,206

)

—

16.77

Forfeited

(71,321

)

(28,476

)

29.50

Outstanding, End of December 31, 2009

22,945,337

10,462,643

27.14

Exercisable, End of December 31, 2009

9,972,272

2,236,641

25.29



Cenovus Energy Inc.		67
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

15. SHARE CAPITAL (continued)

Outstanding TSARs

Exercisable TSARS

Weighted

Average

Weighted

Total

Remaining

Average

Total

Average

Range of Exercise

Number of

Performance

Contractual

Exercise

Number of

Performance

Exercise

Price (C$)

TSARs

Life (years)

Price (C$)

TSARs

Price (C$)

15.00 to 19.99

1,097,538

—

0.13

18.21

1,097,538

—

18.21

20.00 to 24.99

3,965,161

—

1.13

22.95

3,948,676

—

22.94

25.00 to 29.99

12,096,882

7,280,249

3.12

26.50

3,340,019

1,563,747

26.75

30.00 to 34.99

5,593,956

3,182,394

3.08

32.83

1,528,499

672,894

32.68

35.00 to 39.99

109,450

—

3.41

37.14

32,835

—

37.14

40.00 to 44.99

80,850

—

3.44

42.77

24,255

—

42.77

45.00 to 49.99

1,500

—

3.39

45.56

450

—

45.56

22,945,337

10,462,643

2.62

27.14

9,972,272

2,236,641

25.29

16. CAPITAL STRUCTURE

Cenovus’s capital structure is comprised of Shareholders’ Equity plus Long-Term Debt. Cenovus’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due.

Cenovus monitors its capital structure and short-term financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”). These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Debt is defined as the current and long-term portions of long-term debt excluding any amounts with respect to the Partnership Contribution Payable or Receivable.

Cenovus targets a Debt to Capitalization ratio of between 30 and 40 percent.


As at December 31, (US$ millions)	2009			2008
Debt		3,493			3,036
Shareholders’ Equity		9,180			7,748

Total Capitalization		12,673			10,784

Debt to Capitalization ratio		28	%		28	%

Cenovus targets a Debt to Adjusted EBITDA of between 1.0 and 2.0 times.


As at December 31, (US$ millions)	2009			2008			2007

Debt		3,493			3,036			3,690


Net Earnings		648			2,368			1,404
Add (deduct):
Interest, net		218			218			187
Income tax expense		302			725			423
Depreciation, depletion and amortization		1,343			1,318			1,426
Accretion of asset retirement obligation		39			39			28
Foreign exchange (gain) loss, net		290			(250	)		380
Other (income) loss, net		(2	)		3			4

Adjusted EBITDA		2,838			4,421			3,852

Debt to Adjusted EBITDA		1.2	x		0.7	x		1.0	x



Cenovus Energy Inc.		68
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

16. CAPITAL STRUCTURE (continued)

It is Cenovus’s intention to maintain an investment grade rating to ensure it has continuous access to capital and the financial flexibility to fund its capital programs, meet its financial obligations and finance potential acquisitions. Cenovus will maintain a high level of capital discipline and manage its capital structure to ensure sufficient liquidity through all stages of the economic cycle. To manage the capital structure, Cenovus may adjust capital and operating spending, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new shares, issue new debt, draw down on its credit facility or repay existing debt.

Cenovus’s capital structure, objectives and targets have remained unchanged over the periods presented. At December 31, 2009, Cenovus is in compliance with all of the terms of its debt agreements.

17. COMPENSATION PLANS

Cenovus has in place a number of programs whereby employees may be granted the following share-based long-term incentives:

•

Tandem Share Appreciation Rights (“TSARs”)

All options to purchase Common Shares issued under the Cenovus Employee Stock Option Plan, with the exception of a limited number of Cenovus Replacement Options, as described in Note 15, have an associated TSAR attached to them whereby the option holder has the right to receive a cash payment equal to the excess of the market price of Cenovus’s Common Shares at the time of exercise over the exercise price of the right in lieu of exercising the option. The TSARs vest and expire under the same terms and conditions as the underlying option. Certain of the TSARs (“Performance TSARS”) have an additional vesting requirement which is subject to the achievement of prescribed performance relative to key pre-determined measures. Performance TSARs that do not vest when eligible are forfeited.

•

Share Appreciation Rights (“SARs”)

Share Appreciation Rights (“SARs”) entitle the employee to receive a cash payment equal to the excess of the market price of Cenovus’s Common Shares at the time of exercise over the exercise price of the right. SARs are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years and expire five years after the original grant date. Certain of the SARs (“Performance SARs”) have an additional vesting requirement which is subject to the achievement of prescribed performance relative to key pre-determined measures. Performance SARs that do not vest when eligible are forfeited.

In accordance with the Arrangement with EnCana described in Note 2, each Cenovus employee holding an original EnCana long-term incentive unit of the same nature transferred their right to Cenovus in exchange for a Cenovus Replacement Unit and to EnCana for an EnCana Replacement Unit. The terms and conditions of the Cenovus and EnCana Replacement Units are similar to the terms and conditions of the original EnCana unit. The original exercise price of the EnCana unit was apportioned to the Cenovus and EnCana Replacement Units based on the one day weighted average trading price of Cenovus’s common share price relative to that of EnCana’s common share price on the TSX on December 2, 2009. Cenovus is required to reimburse EnCana in respect of cash payments made by EnCana to Cenovus employees for the EnCana Replacement Units they hold. No further EnCana Replacement Units will be granted to Cenovus employees.

All of these share-based long-term incentive programs have similar vesting provisions as the Cenovus stock option plan. Cenovus Units and Cenovus Replacement Units are measured against the Cenovus common share price and EnCana Replacement Units are measured against the EnCana common share price.



Cenovus Energy Inc.		69
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

17. COMPENSATION PLANS (continued)

The Company has recorded a liability in the Consolidated Balance Sheet for EnCana Replacement Units held by the Company’s employees using the fair value method. The fair value of each EnCana Replacement Unit granted is estimated using the Black-Scholes-Merton model with weighted average assumptions as follows:


	2009

Risk Free Rate		1.46	%
Dividend Yield		2.45	%
Volatility		26.17	%
EnCana’s Closing Common Share Price at December 31, 2009	C$	34.11

A) Tandem Share Appreciation Rights

The following tables summarize the information related to the TSARs held by Cenovus employees:

Weighted

Total

Average

Number of

Performance

Exercise

As at December 31, 2009

TSARs

Price (C$)

Replacement TSARs — November 30, 2009

16,431,032

8,053,074

27.51

Granted

67,500

—

25.66

Exercised — SARs

(12,755

)

—

18.43

Exercised — Options

(31,050

)

—

18.13

Outstanding, End of December 31, 2009

16,454,727

8,053,074

27.52

Exercisable, End of December 31, 2009

6,107,015

1,526,893

25.68

Outstanding TSARs

Exercisable TSARs

Weighted

Average

Weighted

Total

Remaining

Average

Total

Average

Range of Exercise

Number of

Performance

Contractual

Exercise

Number of

Performance

Exercise

Price (C$)

TSARs

Life (years)

Price (C$)

TSARs

Price (C$)

15.00 to 19.99

661,202

—

0.13

18.25

661,202

—

18.25

20.00 to 24.99

2,298,334

—

1.17

22.94

2,261,029

—

22.94

25.00 to 29.99

8,878,174

5,390,982

3.33

26.46

1,988,135

964,003

26.76

30.00 to 34.99

4,418,817

2,662,092

3.11

32.90

1,137,189

562,890

32.82

35.00 to 39.99

124,350

—

3.45

37.14

37,305

—

37.14

40.00 to 44.99

71,850

—

3.45

43.31

21,555

—

43.31

45.00 to 49.99

2,000

—

3.39

45.56

600

—

45.56

16,454,727

8,053,074

2.84

27.52

6,107,015

1,526,893

25.68

For the year ended December 31, 2009, Cenovus recorded a reduction of compensation cost of $4 million related to TSARs.

B) Share Appreciation Rights

The following tables summarize the information related to the SARs held by Cenovus employees:

Weighted

Total

Average

Number of

Performance

Exercise

As at December 31, 2009

SARs

Price (C$)

Replacement SARs — November 30, 2009

44,657

23,932

29.38

Outstanding, December 31, 2009

44,657

23,932

29.38

Exercisable, December 31, 2009

4,557

2,532

32.96



Cenovus Energy Inc.		70
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

17. COMPENSATION PLANS (continued)

Outstanding SARs

Exercisable SARs

Weighted

Average

Weighted

Total

Remaining

Average

Total

Average

Range of Exercise

Number of

Performance

Contractual

Exercise

Number of

Performance

Exercise

Price (C$)

SARs

Life (years)

Price (C$)

SARs

Price (C$)

25.00 to 29.99

25,925

11,950

4.13

26.79

—

30.00 to 34.99

18,732

11,982

3.12

32.96

4,557

2,532

32.96

44,657

23,932

3.71

29.38

4,557

2,532

32.96

For the year ended December 31, 2009, Cenovus has not recorded any compensation costs related to the SARs.

C) EnCana Replacement Tandem Share Appreciation Rights

The following tables summarize information related to the EnCana Replacement TSARs held by Cenovus employees:

Weighted

Average

Total Number of

Performance

Exercise

As at December 31, 2009

TSARs

Price (C$)

Replacement TSARs — November 30, 2009

16,431,032

8,053,074

30.41

Exercised — SARs

(73,322

)

(1,382

)

20.67

Exercised — Options

(1,050

)

—

17.96

Outstanding, End of December 31, 2009

16,356,660

8,051,692

30.46

Exercisable, End of December 31, 2009

6,076,448

1,525,511

28.43

Outstanding EnCana Replacement TSARs

Exercisable EnCana Replacement TSARs

Weighted

Average

Weighted

Total

Remaining

Average

Total

Average

Range of Exercise

Number of

Performance

Contractual

Exercise

Number of

Performance

Exercise

Price (C$)

TSARs

Life (years)

Price (C$)

TSARs

Price (C$)

15.00 to 19.99

2,960

—

0.08

19.08

2,960

—

19.08

20.00 to 24.99

652,542

—

0.18

20.27

646,942

—

20.25

25.00 to 29.99

10,800,826

5,389,600

2.89

28.39

4,035,672

962,621

27.17

30.00 to 34.99

411,720

—

2.41

32.29

264,565

—

32.09

35.00 to 39.99

4,341,562

2,662,092

3.12

36.47

1,082,194

562,890

36.46

40.00 to 44.99

74,200

—

3.49

42.28

22,260

—

42.28

45.00 to 49.99

70,850

—

3.45

47.94

21,255

—

47.94

50.00 to 54.99

2,000

—

3.39

50.39

600

—

50.39

16,356,660

8,051,692

2.84

30.46

6,076,448

1,525,511

28.43

For the year ended December 31, 2009, the Company recorded compensation costs of $55 million related to the EnCana Replacement TSARs.

D) EnCana Replacement Share Appreciation Rights

The following tables summarize information related to the EnCana Replacement SARs held by Cenovus employees:

Weighted

Total

Average

Number of

Performance

Exercise

As at December 31, 2009

SARs

TSARs

Price (C$)

EnCana Replacement SARs — November 30, 2009

44,657

23,932

32.48

Outstanding, End of December 31, 2009

44,657

23,932

32.48

Exercisable, End of December 31, 2009

4,557

2,532

36.44



Cenovus Energy Inc.		71
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

17. COMPENSATION PLANS (continued)

Outstanding EnCana Replacement SARs

Exercisable EnCana Replacement SARs

Weighted

Average

Weighted

Total

Remaining

Average

Total

Average

Range of Exercise

Number of

Performance

Contractual

Exercise

Number of

Performance

Exercise

Price (C$)

SARs

Life (years)

Price (C$)

SARs

Price (C$)

25.00 to 29.99

22,925

11,950

4.09

29.23

—

30.00 to 34.99

3,000

—

4.45

32.55

—

35.00 to 39.99

18,732

11,982

3.12

36.44

4,557

2,532

36.44

44,657

23,932

3.71

32.48

4,557

2,532

36.44

For the year ended December 31, 2009, the Company has not recorded any compensation costs related to the EnCana Replacement SARs.

E) Deferred Share Units (“DSUs”)

Cenovus has in place a program whereby directors, officers and employees are issued Deferred Share Units (“DSUs”), which are equivalent in value to a common share of the Company. Commencing in 2009, employees had the option to convert either 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, can be redeemed in accordance with terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment.

Pursuant to the terms of the Arrangement, EnCana DSUs credited to directors, officers and employees of Cenovus were exchanged for Cenovus DSUs. The fair value of the Cenovus DSUs credited to each holder was based on the fair market value of Cenovus Common Shares relative to EnCana common shares prior to the effective date of the Arrangement.


	Outstanding
As at December 31, 2009	DSUs

Outstanding, November 30, 2009		762,011
Units in Lieu of Dividends		6,092

Outstanding, End of December 31, 2009		768,103

For the year ended December 31, 2009, the Company has not recorded any compensation costs related to DSUs.

F) EnCana Pre-Arrangement Stock-Based Compensation Costs

Included in the financial information prior to the Arrangement, the Company recorded compensation costs for the following EnCana plans:


(US$ millions)	2009		2008			2007

EnCana TSARs		4		(9	)		83
EnCana SARs		1		—			—
EnCana DSUs		2		1			7
EnCana PSUs		—		—			16



Cenovus Energy Inc.		72
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

17. COMPENSATION PLANS (continued)

G) Pensions and Other Post-Employment Benefits

The Company sponsors defined benefit and defined contribution plans, providing pension and other post-employment benefits (“OPEB”) to its employees.

The Company is required to file an actuarial valuation of its pension plans with the provincial regulator at least every three years. An actuarial valuation as at November 30, 2009 will be filed during the first half of 2010.

Pursuant to the Arrangement, the liabilities and assets related to Cenovus employees, as determined by actuarial consultants, transferred to the Cenovus Pension Plans effective November 30, 2009. The 2009 Pension and OPEB amounts reflect activity since the effective date.

The 2008 Pension and OPEB amounts represent Cenovus’s proportionate share of EnCana’s pension plans related to active employees. The going concern liabilities and assets related to retirees prior to the Arrangement remained with EnCana.

Information related to defined benefit pension and other post-employment benefit plans, based on actuarial estimations as at December 31, 2009 is as follows:

Accrued Benefit Obligation


	Pension Benefits				OPEB
As at December 31, (US$ millions)	2009		2008		2009		2008

Accrued Benefit Obligation Pursuant to the Arrangement		50				11
Current service cost		—				—
Interest cost		—				—
Benefits paid		—				—
Actuarial (gain) loss		3				—
Foreign exchange (gain) loss		1				—

Accrued Benefit Obligation, End of Year		54		36		11		7

Plan Assets


	Pension Benefits				OPEB
As at December 31, (US$ millions)	2009		2008		2009		2008

Fair Value of Plan Assets Pursuant to the Arrangement		50				—
Actuarial gain (loss) on return of plan assets		1				—
Employer contributions		—				—
Benefits paid		—				—
Foreign exchange (gain) loss		1				—

Fair Value of Plan Assets, End of Year		52		32		—		—

Accrued Benefit Asset (Liability)


	Pension Benefits					OPEB
As at December 31, (US$ millions)	2009			2008		2009			2008

Funded Status-Plan Assets (less) than Benefit Obligation		(2	)				(11	)
Amounts Not Recognized:
Unamortized net actuarial (gain) loss		14					(1	)
Unamortized past service cost		—					1

Accrued Benefit Asset (Liability)		12			6		(11	)		(6	)



Cenovus Energy Inc.		73
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

17. COMPENSATION PLANS (continued)


	Pension Benefits				OPEB
As at December 31, (US$ millions)	2009		2008		2009			2008

Prepaid Benefit Cost		12				—
Accrued Benefit Cost		—				(11	)

Net Amount Recognized		12		6		(11	)		(6	)

The Company’s OPEB plans are funded on an as required basis.

The weighted average assumptions used to determine benefit obligations are as follows:


As at December 31,	2009			2008			2009			2008

Discount Rate		6.00	%		6.25	%		6.00	%		6.25	%
Rate of Compensation Increase		4.05	%		4.16	%		5.77	%		6.00	%

The average remaining service period of the active employees covered by the defined benefit pension plan is 4 years. The average remaining service period of the active employees covered by the OPEB plan is 11 years.

Assumed health care cost trend rates are as follows:


As at December 31,	2009			2008

Health Care Cost Trend Rate for Next Year		10.00	%		9.50	%
Rate that the Trend Rate Gradually Trends To		5.00	%		5.00	%
Year that the Trend Rate Reaches the Rate which it is Expected to Remain At		2020			2017

Assumed health care cost trend rates have an effect on the amounts reported for the OPEB plans. A one percentage point change in assumed health care cost trend rates would have the following effects:


	One Percentage Point		One Percentage Point
(US$ millions)	Increase		Decrease

Effect on Post-Retirement Benefit Obligation		1		(1	)

The Company’s pension plan asset allocations are as follows:


					As at		As at
					December 31,		December 31,		Rate of
	Normal		Range		2009		2008		Return

Domestic Equity		35		25-45		39		34
Foreign Equity		30		20-40		23		25
Bonds		30		20-40		29		33
Real Estate and Other		5		0-20		9		8

Total		100				100		100		6.75	%

The expected rate of return on plan assets is based on historical and projected rates of return for each asset class in the plan investment portfolio. The objective of the asset allocation policy is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The Supplemental Pension Plan is funded through a retirement compensation arrangement and is subject to the applicable Canada Revenue Agency regulations.



Cenovus Energy Inc.		74
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

17. COMPENSATION PLANS (continued)

The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment, credit rating categories and foreign currency exposure.

The Company’s contributions to the pension plans are subject to the results of the actuarial valuation and direction by the Human Resources and Compensation Committee of the Board.

Estimated future payment of pension and other benefits are as follows:


(US$ millions)	Pension Benefits		OPEB

2010		1		—
2011		1		—
2012		2		—
2013		2		1
2014		3		1
2015 – 2019		20		6

Total		29		8

18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Cenovus’s consolidated financial assets and liabilities are comprised of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, the Partnership Contribution Receivable and Payable, risk management assets and liabilities, and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments. Fair values of financial assets and liabilities, summarized information related to risk management positions, and discussion of risks associated with financial assets and liabilities are presented as follows. The information contained within Note 18 is based on carve-out information for the periods prior to December 1, 2009.

A) Fair Value of Financial Assets and Liabilities

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amount due to the short-term maturity of those instruments.

The fair values of the Partnership Contribution Receivable and Partnership Contribution Payable approximate their carrying amount due to the specific non-tradeable nature of these instruments in relation to the creation of the integrated oil business venture.

Risk management assets and liabilities are recorded at their estimated fair value based on mark-to-market accounting, using quoted market prices or, in their absence, third-party market indications and forecasts.

Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on market information.



Cenovus Energy Inc.		75
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

The fair value of financial assets and liabilities, including current portions thereof were as follows:

2009

2008

Carrying

Fair

Carrying

Fair

As at December 31, (US$ millions)

Amount

Value

Amount

Value

Financial Assets

Held-for-trading:

Cash and cash equivalents

148

153

Risk management assets

719

Loans and Receivables:

Accounts receivable and accrued revenues

874

598

Partnership Contribution Receivable

2,834

3,147

Financial Liabilities

Held-for-trading:

Risk management liabilities

Other Financial Liabilities:

Accounts payable and accrued liabilities

1,444

1,114

Long-term debt

3,493

3,788

3,036

Partnership Contribution Payable

2,857

3,163

B) Risk Management Assets and Liabilities

Under the terms of the Arrangement with EnCana, the risk management positions at November 30, 2009 were allocated to Cenovus based upon Cenovus’s proportion of the related volumes covered by the contracts. To effect the allocation, Cenovus entered into a contract with EnCana with the same terms and conditions as between EnCana and the third parties to the existing contracts. All positions entered into after the Arrangement have been negotiated between Cenovus and third parties.

Net Risk Management Position


As at December 31, (US$ millions)	2009			2008

Risk Management
Current asset		58			681
Long-term asset		1			38

		59			719

Risk Management
Current liability		67			40
Long-term liability		4			—

		71			40

Net Risk Management Asset (Liability)		(12	)		679

Of the $12 million net risk management liability balance at December 31, 2009, a liability of $14 million relates to the contract with EnCana.

Summary of Unrealized Risk Management Positions


	2009							2008
	Risk Management							Risk Management
As at December 31, (US$ millions)	Asset		Liability		Net			Asset		Liability		Net

Commodity Prices
Natural Gas		51		—		51			618		—		618
Crude Oil		8		63		(55	)		92		40		52
Power		—		8		(8	)		9		—		9

Total Fair Value		59		71		(12	)		719		40		679



Cenovus Energy Inc.		76
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Net Fair Value Methodologies Used to Calculate Unrealized Risk Management Positions


As at December 31, (US$ millions)	2009			2008

Prices actively quoted		7			521
Prices sourced from observable data or market corroboration		(19	)		158

Total Fair Value		(12	)		679

Prices actively quoted refers to the fair value of contracts valued using quoted prices in an active market. Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.

Net Fair Value of Commodity Price Positions at December 31, 2009

Fair

(US$ millions)

Notional Volumes

Term

Average Price

Value

Crude Oil Contracts

Fixed Price Contracts

WTI NYMEX Fixed Price

24,600 bbls/d

2010

76.99 US$/bbl

(47

)

Other Financial Positions*

)

Crude Oil Fair Value Position

(55

)

Natural Gas Contracts

Fixed Price Contracts

NYMEX Fixed Price

437 MMcf/d

2010

6.08 US$/Mcf

NYMEX Fixed Price

56 MMcf/d

2011

6.75 US$/Mcf

Basis Contracts**

Canada

28 MMcf/d

2010

)

Canada

2011-2013

)

Natural Gas Fair Value Position

Power Purchase Contracts

Power Fair Value Position

)


*		Other financial positions are part of ongoing operations to market the Company’s production.

**		Cenovus has entered into swaps to protect against widening natural gas price differentials between production areas in Canada and various sales points. These basis swaps are priced using both fixed prices and basis prices determined as a percentage of NYMEX.

Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions


	Realized Gain (Loss)
For the years ended December 31, (US$ millions)	2009			2008			2007

Revenues, Net of Royalties		1,005			(323	)		136
Operating Expenses and Other		(32	)		24			3

Gain (Loss) on Risk Management		973			(299	)		139


	Unrealized Gain (Loss)
For the years ended December 31, (US$ millions)	2009			2008		2007

Revenues, Net of Royalties		(639	)		727		(349	)
Operating Expenses and Other		(28	)		7		1

Gain (Loss) on Risk Management		(667	)		734		(348	)



Cenovus Energy Inc.		77
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Reconciliation of Unrealized Risk Management Positions


	2009						2008		2007
				Total			Total		Total
	Fair			Unrealized			Unrealized		Unrealized
For the years ended December 31, (US$ millions)	Value			Gain (Loss)			Gain (Loss)		Gain (Loss)

Fair Value of Contracts, Beginning of Year		653
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During the Year		306			306			435		(215	)
Other		—			—			—		6
Foreign Exchange Gain (Loss) on Canadian Dollar Contracts		2			—			—		—
Fair Value of Contracts Realized During the Year		(973	)		(973	)		299		(139	)

Fair Value of Contracts, End of Year		(12	)		(667	)		734		(348	)

Commodity Price Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. When assessing the potential impact of these commodity price changes, Management believes 10 percent volatility is a reasonable measure. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting net earnings as at December 31, 2009 as follows:


	10% Price			10% Price
(US$ millions)	Increase			Decrease

Natural gas price		(102	)		102
Crude oil price		(82	)		82
Power price		5			(5	)

C) Risks Associated with Financial Assets and Liabilities

Commodity Price Risk

Commodity price risk arises from the effect that fluctuations of future commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy is not to use derivative financial instruments for speculative purposes.

Crude Oil — The Company has partially mitigated its exposure to the commodity price risk on its crude oil sales and condensate supply with fixed price swaps.

Natural Gas — To partially mitigate the natural gas commodity price risk, the Company has entered into swaps, which fix the NYMEX prices. To help protect against widening natural gas price differentials in various production areas, Cenovus has entered into swaps to manage the price differentials between these production areas and various sales points.

Power — The Company has in place two Canadian dollar denominated derivative contracts, which commenced January 1, 2007 for a period of 11 years, to manage its electricity consumption costs.



Cenovus Energy Inc.		78
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Credit Risk

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit policies governing the Company’s credit portfolio and with credit practices that limit transactions according to counterparties’ credit quality. All foreign currency agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at December 31, 2009, over 98 percent (2008-95 percent) of Cenovus’s accounts receivable and financial derivative credit exposures are with investment grade counterparties.

At December 31, 2009, Cenovus had two counterparties (2008-two counterparties) whose net settlement position individually account for more than 15 percent of the fair value of the outstanding in-the-money net financial and physical contracts by counterparty. The maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets and the Partnership Contribution Receivable is the total carrying value. The current concentration of this credit risk resides with EnCana and a AAA rated counterparty. Cenovus’s exposure to EnCana is expected to reduce substantially by the end of the first quarter 2010 as Cenovus begins to market its own physical gas to the market. Cenovus’s exposure to its counterparties is acceptable and within Credit Policy tolerances.

Liquidity Risk

Liquidity risk is the risk that Cenovus will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity through the active management of cash and debt. As disclosed in Note 16, Cenovus targets a Debt to Capitalization ratio between 30 and 40 percent and a Debt to Adjusted EBITDA of between 1.0 to 2.0 times to manage the Company’s overall debt position.

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities and undrawn credit facilities. At December 31, 2009, Cenovus had approximately $2.3 billion in unused credit capacity available on its committed bank credit facility.

It is Cenovus’s intention to maintain investment grade credit ratings on its senior unsecured debt. DBRS Limited (“DBRS”) has assigned a rating of A (low) with a “Stable” outlook, Standard and Poor’s Corporation has assigned a rating of BBB+ with a “Stable” outlook and Moody’s Investors Service Inc. has assigned a rating of Baa2 with a “Stable” outlook.

Cash outflows relating to financial liabilities are outlined in the table below:


(US$ millions)	Less than 1 Year		1 – 3 Years		4 – 5 Years		Thereafter		Total

Accounts Payable and Accrued Liabilities		1,444		—		—		—		1,444
Risk Management Liabilities		67		4		—		—		71
Long-Term Debt*		227		468		1,209		5,433		7,337
Partnership Contribution Payable*		489		978		978		1,099		3,544


*		Principal and interest, including current portion.



Cenovus Energy Inc.		79
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Included in Cenovus’s long-term debt obligations of $3,493 million at December 31, 2009, are $56 million in principal obligations related to prime rate and LIBOR based loans. These amounts are fully supported by the Company’s revolving syndicated credit facility, which have no repayment requirements within the next year. All outstanding amounts related to the prime rate and LIBOR based loans were drawn on the 3-year tranche of the revolving syndicated credit facility. Based on the current maturity dates of the 3-year tranche, these amounts are included in cash outflows for the period disclosed as “1-3 Years.” Further information on Long-Term Debt is included in Note 13.

Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results. Cenovus’s functional currency is Canadian dollars; however, the Company reports its results in U.S. dollars, unless otherwise indicated. As the effects of foreign exchange fluctuations are embedded in the Company’s results, the total effect of foreign exchange fluctuations is not separately identifiable.

As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada and the translation of the U.S. dollar Partnership Contribution Receivable issued from Canada. At December 31, 2009, Cenovus had $3,525 million in U.S. dollar debt issued from Canada ($1,804 million at December 31, 2008) and $2,834 million related to the U.S. dollar Partnership Contribution Receivable ($3,147 million at December 31, 2008). A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $7 million change in foreign exchange (gain) loss at December 31, 2009 (2008-$11 million).

Interest Rate Risk

Interest rate risk arises from changes in market interest rates that may affect the earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt.

At December 31, 2009, the majority of the Company’s debt is fixed-rate debt and as a result, the increase or decrease in net earnings for each one percent change in interest rates on floating rate debt amounts to nil (December 31, 2008-$4 million; 2007-$5 million).

19. SUPPLEMENTARY INFORMATION

A) Per Share Amounts


For the years ended December 31, (millions)	2009		2008		2007

Weighted Average Common Shares Outstanding — Basic		751.0		750.1		756.8
Effect of Stock Options and Other Dilutive Securities		0.4		1.7		7.8

Weighted Average Common Shares Outstanding — Diluted		751.4		751.8		764.6

Since Cenovus’s shares were issued pursuant to the Arrangement, the per share amounts disclosed above are based on EnCana’s common shares.



Cenovus Energy Inc.		80
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

19. SUPPLEMENTARY INFORMATION (continued)

B) Supplementary Cash Flow Information


For the years ended December 31, (US$ millions)	2009		2008		2007

Interest Paid		376		395		408
Income Taxes Paid		1,145		508		536

Income taxes paid in 2009 includes amounts paid to EnCana as a result of the dissolution of a partnership as part of the Arrangement.

20. COMMITMENTS AND CONTINGENCIES

Commitments

As part of normal operations, the Company has committed to certain amounts over the next five years and thereafter as follows:


(US$ millions)	2010		2011		2012		2013		2014		Thereafter		Total

Operating Leases (Building Leases)		26		27		34		72		76		1,575		1,810
Pipeline Transportation		101		95		68		141		141		923		1,469
Purchases of Goods and Services		98		9		4		3		—		—		114
Capital Commitments		105		85		33		—		—		—		223
Product Purchases		26		23		22		22		22		28		143

Total Payments		356		239		161		238		239		2,526		3,759

Product Sales		46		48		52		53		55		119		373

In addition to the above, Cenovus’s share of commitments related to its risk management program are disclosed in Note 18.

Contingencies

Legal Proceedings

Cenovus is involved in various legal claims associated with the normal course of operations. Cenovus believes it has made adequate provisions for such legal claims.



Cenovus Energy Inc.		81
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

20. COMMITMENTS AND CONTINGENCIES (continued)

Asset Retirement

Cenovus is responsible for the retirement of long-lived assets related to its oil and gas properties, refining facilities and Midstream facilities at the end of their useful lives. Cenovus has recognized a liability of $1,096 million based on current legislation and estimated costs. Actual costs may differ from those estimated due to changes in legislation and changes in costs.

Income Tax Matters

The tax interpretations, regulations and legislation in the various jurisdictions that Cenovus operates in are continually changing. As a result, there are usually some tax matters under review. Management believes that the provision for taxes is adequate.

21. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING

The Cenovus Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”) which, in most respects, conform to accounting principles generally accepted in the United States (“U.S. GAAP”). The significant differences between Canadian GAAP and U.S. GAAP are described in this note. The most notable differences are:

	•		full cost accounting;

	•		pensions and other post-employment benefits;

	•		liability-based stock compensation plans;

	•		income taxes;

	•		other comprehensive income;

	•		joint venture accounting; and

	•		inventories.

RECONCILIATION OF NET EARNINGS UNDER CANADIAN GAAP TO U.S. GAAP


For the years ended December 31, (US$ millions)	Note 21		2009			2008			2007

Net Earnings-Canadian GAAP				648			2,368			1,404
Increase (Decrease) in Net Earnings Under U.S. GAAP:
Revenues, net of royalties				—			—			(5	)
Expenses
Operating	C ii)			4			(12	)		1
Depreciation, depletion and amortization	A, C ii)			209			29			148
General and administrative	C ii)			8			(14	)		1
Stock-based compensation-options				—			1			(3	)
Income tax expense		D		(184	)		(32	)		(87	)

Net Earnings-U.S. GAAP				685			2,340			1,459



Cenovus Energy Inc.		82
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

CONSOLIDATED STATEMENT OF EARNINGS AND COMPREHENSIVE INCOME — U.S. GAAP


For the years ended December 31, (US$ millions)	Note 21		2009			2008			2007

Revenues, Net of Royalties				10,140			16,559			13,401
Expenses
Production and mineral taxes				38			75			63
Transportation and selling				672			963			756
Operating	C ii)			1,150			1,235			1,113
Purchased product				5,250			9,710			7,476
Depreciation, depletion and amortization	A, C ii)			1,134			1,289			1,278
General and Administrative	C ii)			180			181			144
Interest, net				218			218			187
Accretion of asset retirement obligation				39			39			28
Foreign exchange (gain) loss, net				290			(250	)		380
Stock-based compensation-options				—			(1	)		3
Other (gain) loss, net				(2	)		3			4

Earnings Before Income Tax				1,171			3,097			1,969
Income tax expense		D		486			757			510

Net Earnings-U.S. GAAP				685			2,340			1,459


Other Comprehensive Income, Net of Tax
Foreign Currency Translation Adjustment				1,872			(2,075	)		1,133
Compensation Plans				31			(8	)		—

Comprehensive Income				2,588			257			2,592

CONDENSED CONSOLIDATED BALANCE SHEET — U.S. GAAP


			2009						2008
As at December 31, (US$ millions)	Note 21		As Reported			U.S. GAAP			As Reported			U.S. GAAP

Assets
Current Assets		G		2,284			2,284			2,248			2,248
Property, Plant and Equipment (includes unproved properties and major development projects of $1,921 and $715 as of December 31, 2009 and 2008, respectively)	A, C ii)			26,255			26,237			21,175			21,182
Accumulated Depreciation, Depletion and Amortization				(11,718	)		(12,523	)		(8,915	)		(9,798	)

Property, Plant and Equipment, net (Full Cost Method for Oil and Gas Activities)				14,537			13,714			12,260			11,384
Other Assets		C i)		131			138			150			133
Partnership Contribution Receivable				2,504			2,504			2,834			2,834
Risk Management				1			1			38			38
Goodwill				1,095			1,095			936			936

				20,552			19,736			18,466			17,573

Liabilities and Net Investment
Current Liabilities	C i), C ii), D			1,836			1,937			1,798			1,918
Long-Term Debt				3,493			3,493			2,952			2,952
Other Liabilities	C i), C ii)			54			55			52			65
Partnership Contribution Payable				2,532			2,532			2,857			2,857
Risk Management				4			4			—			—
Asset Retirement Obligation				1,096			1,096			648			648
Deferred Income Taxes		D		2,357			2,187			2,411			2,093

				11,372			11,304			10,718			10,533

Shareholders’ Equity		E		9,180			8,432			7,748			7,040

				20,552			19,736			18,466			17,573



Cenovus Energy Inc.		83
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS — U.S. GAAP


For the years ended December 31, (US$ millions)	2009			2008			2007

Operating Activities
Net earnings		685			2,340			1,459
Depreciation, depletion and amortization		1,134			1,289			1,278
Deferred income taxes		(371	)		416			(168	)
Unrealized (gain) loss on risk management		667			(734	)		353
Unrealized foreign exchange (gain) loss		313			(259	)		383
Accretion of asset retirement obligation		39			39			28
Other (income) loss, net		1			(2	)		124
Net change in other assets and liabilities		(23	)		(89	)		(48	)
Net change in non-cash working capital		1,051			(316	)		(417	)

Cash From Operating Activities		3,496			2,684			2,992

Cash (Used in) Investing Activities		(1,780	)		(1,964	)		(1,533	)

Net Cash Provided before Financing Activities		1,716			720			1,459

Cash From (Used in) Financing Activities		(1,730	)		(849	)		(1,270	)

Notes:

A) Full Cost Accounting

Under U.S. GAAP, a ceiling test is applied to ensure the unamortized capitalized costs in each cost centre do not exceed the sum, net of applicable income taxes, of the present value, discounted at 10 percent, of the estimated future net revenues calculated on the basis of estimated value of future production from proved reserves using oil and gas prices at the balance sheet date, less related unescalated estimated future development and production costs, plus unimpaired unproved property costs. For 2009, depletion charges under U.S. GAAP were also calculated by reference to proved reserves estimated using an average price for the prior 12-month period. For 2008 and 2007, depletion charges under U.S. GAAP were calculated by reference to proved reserves estimated using oil and gas prices at the balance sheet date.

Under Canadian GAAP, a similar ceiling test calculation is performed with the exception that cash flows from proved reserves are undiscounted and utilize forecast pricing and future development and production costs to determine whether impairment exists. The impairment amount is measured using the fair value of proved and probable reserves. Depletion charges under Canadian GAAP are also calculated by reference to proved reserves estimated using estimated future prices and costs.

At December 31, 2008, Cenovus’s capitalized costs of oil and gas properties in Canada exceeded the full cost ceiling resulting in a non-cash U.S. GAAP write-down of $60 million charged to DD&A (2007-nil). Additional depletion was also recorded in 2006, and certain prior years, as a result of the ceiling test difference between Canadian GAAP and U.S. GAAP. As a result, the depletion base of unamortized capitalized costs is less for U.S. GAAP purposes.

The U.S. GAAP adjustment for the difference in depletion calculations results in an impact to DD&A charges and foreign currency translation adjustment of $207.8 million decrease and $13.9 million increase respectively (2008-$92.4 million decrease and $8.5 million decrease; 2007-$147.8 million decrease and $8.9 million increase).



Cenovus Energy Inc.		84
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

21. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (continued)

B) Property, Plant and Equipment Allocation

Net property, plant and equipment related to Canadian upstream oil and gas activities have been allocated for U.S. GAAP carve-out purposes using the same methodology as the carve-out allocation for Canadian GAAP purposes.

The balances related to Canadian upstream operations have been allocated between Cenovus and EnCana in accordance with the CICA Handbook Accounting Guideline ACG-16, based on the ratio of future net revenue, discounted at 10 percent, of the properties carved out to the discounted future net revenue of all proved properties in Canada using the reserve reports dated December 31, 2008 and December 31, 2007. Future net revenue is the estimated net amount to be received with respect to development and production of crude oil and natural gas reserves, the value of which has been determined by independent reserve evaluators.

C) Compensation Plans

i) Pensions and Other Post-Employment Benefits

Under U.S. GAAP, ASC 715-30, “Compensation - Retirement Benefits”, requires Cenovus to recognize the over-funded or under-funded status of defined benefit and post-employment plans on the balance sheet as an asset or liability and to recognize changes in the funded status through Other Comprehensive Income. Canadian GAAP does not require Cenovus to recognize the funded status of these plans on its balance sheet.

ii) Liability-Based Stock Compensation Plans

Under Canadian GAAP, obligations for liability-based stock compensation plans are recorded using the intrinsic-value method of accounting. For U.S. GAAP purposes, Cenovus adopted ASC 718, “Compensation — Stock Compensation” for the year ended December 31, 2006 using the modified-prospective approach. Under ASC 718, liability-based stock compensation plans, including tandem share appreciation rights, performance tandem share appreciation rights, share appreciation rights, performance share appreciation rights and deferred share units, are required to be re-measured at fair value at each reporting period up until the settlement date.

To the extent compensation cost relates to employees directly involved in crude oil and natural gas development activities, certain amounts are capitalized to property, plant and equipment. Amounts not capitalized are recognized as administrative expenses or operating expenses. The current period adjustments have the following impact:

	•		Net property, plant and equipment decreased by $24.2 million (2008-$14.6 million increase)

	•		Current liabilities decreased by $39.5 million (2008-$41.4 million increase)

	•		Other liabilities increased by $1.6 million (2008-$0.2 million decrease)

	•		Other comprehensive income-nil (2008-$3.0 million increase)

	•		Operating expenses decreased by $3.8 million (2008-$11.6 million increase)

	•		Administrative expenses decreased by $7.9 million (2008-$14.5 million increase)

	•		Depreciation, depletion and amortization expenses decreased by $1.6 million (2008-$3.8 million increase)



Cenovus Energy Inc.		85
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

21. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (continued)

D) Income Taxes

U.S. GAAP uses enacted tax rates and legislative changes to calculate current and deferred income taxes, whereas Canadian GAAP uses substantively enacted tax rates and legislative changes. In 2007, a Canadian tax legislative change was substantively enacted for Canadian GAAP; however, this tax legislative change was not considered enacted for U.S. GAAP by December 31, 2007 and 2008. This tax legislative change is still not considered enacted. Accordingly, there was no difference in 2009 (2008-nil; 2007-increase to income tax expense of $76 million) for U.S. GAAP.

The remaining differences resulted from the deferred income tax adjustments included in the Reconciliation of Net Earnings under Canadian GAAP to U.S. GAAP and the Condensed Consolidated Balance Sheet include the effect of such rate differences, if any, as well as the tax effect of the other reconciling items noted.

In 2009, Cenovus incurred losses in one of its subsidiary company which were recognized and included in calculating future income taxes for Canadian GAAP purposes on the basis that the tax legislative changes noted above were substantially enacted. For U.S. GAAP, these losses can not be recognized as the tax legislative changes have not been enacted by December 31, 2009. The income tax expense has been increased by $124.0 million (2008 and 2007-nil) to record the difference between Canadian and U.S. GAAP.

The following table provides a reconciliation of the statutory rate to the actual tax rate:


For the years Ended December 31, (US$ millions)	2009			2008			2007

Net Earnings Before Income Tax-U.S. GAAP		1,171			3,097			1,969
Canadian Statutory Rate		29.2	%		29.7	%		32.3	%

Expected Income Tax		342			919			636
Effect on Taxes Resulting from:
Statutory and other rate differences		(9	)		(79	)		17
Effect of tax rate changes		—			—			(147	)
Non-taxable downstream partnership income		6			6			(70	)
International financing		(118	)		(127	)		—
Foreign exchange (gains) losses not included in net earnings		67			11			—
Non-taxable capital (gains) losses		11			(50	)		45
Unrecognized non-capital losses		124			—			—
Other		63			77			29

Income Tax-U.S. GAAP		486			757			510

Effective Tax Rate		41.5	%		24.4	%		25.9	%

The net deferred income tax liability is comprised of:


As at December 31, (US$ millions)	2009			2008

Deferred Tax Liabilities
Property, plant and equipment in excess of tax values		2,224			1,737
Timing of partnership items		9			470
Risk management		16			—
Other		75			185
Deferred Tax Assets
Non-capital and net operating losses carried forward		(106	)		(19	)
Other		(31	)		(280	)

Net Deferred Income Tax Liability		2,187			2,093



Cenovus Energy Inc.		86
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

21. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (continued)

E) Other Comprehensive Income

ASC 715-30 requires a change in the funded status of defined benefit and post-employment plans to be recognized on the balance sheet and changes in the funded status through comprehensive income. In 2009, a gain of $30.9 million, net of tax was recognized in other comprehensive income (2008-loss of $7.5 million) as noted in D i). On adoption of ASC 715-30, as required, the transitional amount of $12 million, net of tax was booked directly to Accumulated Other Comprehensive Income.

The foreign currency translation adjustment includes the effect of the accumulated U.S. GAAP differences.

F) Joint Venture with ConocoPhillips

Under Canadian GAAP, the Integrated Oil operations that are jointly controlled are proportionately consolidated. U.S. GAAP requires the Downstream Refining operations included in the Integrated Oil Division be accounted for using the equity method. However, under an accommodation of the U.S. Securities and Exchange Commission, accounting for jointly controlled investments does not require reconciliation from Canadian to U.S. GAAP if the joint venture is jointly controlled by all parties having an equity interest in the entity, which is the case for the Downstream Refining operations. Equity accounting for the Downstream Refining operations would have no impact on Cenovus’s net earnings or retained earnings. As required, the following disclosures are provided for the Downstream Refining operations of the joint venture.


Consolidated Statement of Earnings
For the year ended December 31, (US$ millions)	2009			2008

Operating Cash Flow (See Note 1)		310			(241	)
Depreciation, depletion and amortization		(192	)		(188	)
Other		(11	)		19

Net Earnings (Loss)		107			(410	)


Consolidated Balance Sheet
As at December 31, (US$ millions)	2009		2008

Current Assets		771		321
Long-term Assets		4,872		4,157
Current Liabilities		489		422
Long-term Liabilities		391		35


Consolidated Statement of Cash Flows
For the year ended December 31, (US$ millions)	2009			2008

Cash From/(Used in) Operating Activities		(54	)		118
Cash (Used in) Investing Activities		(905	)		(519	)



Cenovus Energy Inc.		87
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in US$ millions, unless otherwise indicated
For the year ended December 31, 2009

21. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (continued)

G) Inventories

For Canadian GAAP purposes, for the year ended December 31, 2009, the Company recorded an increase in inventory values resulting from a subsequent improvement in commodity prices following a write-down of product inventory. Under U.S. GAAP, this increase in inventory value is not permitted. Since the majority of the impaired inventory was sold during the year, the impact to net earnings for this reconciling difference was immaterial.

H) Recent Accounting Pronouncements

During the year, Cenovus adopted the following pronouncements for U.S. GAAP purposes:

•		ASC 805-10, “Business Combinations,” which is a revised standard and requires assets and liabilities acquired in a business combination, contingent consideration, and certain acquired contingencies to be measured at their fair values as of the date of acquisition. Acquisition-related and restructuring costs are recognized separately from the business combination. This standard was adopted prospectively as of January 1, 2009. The adoption of this standard had no material impact on Cenovus’s U.S. GAAP accounting treatment of business combinations entered into after January 1, 2009.

•		ASC 810-10 “Consolidation,” which requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. The standard also changes the way the U.S. GAAP consolidated statement of earnings is presented by requiring net earnings to include the amounts attributable to both the parent and the non-controlling interest and to disclose these respective amounts. This standard was adopted as of January 1, 2009. The adoption of this standard had no material impact on Cenovus’s Consolidated Financial Statements.

•		In June 2009, the U.S. Financial Accounting Standards Board (“FASB”) issued the Accounting Standards Update (ASU) 2009-01, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” This update establishes the FASB Accounting Standards Codification (“Codification”) as the source of authoritative U.S. generally accepted accounting principles effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Codification did not change existing requirements under U.S. GAAP and as a result, did not impact Cenovus’s Consolidated Financial Statements.

•		The U.S. Securities Exchange Commission’s project, “Modernization of Oil and Gas Reporting” and FASB’s Accounting Standards Update 2010-03 “Oil and Gas Reserve Estimation and Disclosures,” which include provisions that permit the use of new technologies to establish proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Additionally, oil and gas reserves are now reported using an average price based upon the prior 12-month period rather than year-end prices. The new rules and standards were adopted prospectively by Cenovus on December 31, 2009 and affected the reserve estimate used in the calculation of the ceiling test for U.S. GAAP. There was no effect on the ceiling test for the change in rules and standards noted above for 2009. In addition, the FASB standard affected the amounts reported in the Supplementary Oil and Gas Information Topic 932 as discussed in that supplementary information.



Cenovus Energy Inc.		88
Annual Financials 2009		Notes to Consolidated Financial Statements (prepared in US$)

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics


	2009															2008
(US$ millions, except per share amounts)	Year			Q4			Q3			Q2			Q1			Year			Q4			Q3			Q2			Q1

Revenues, net of royalties		10,140			2,835			2,714			2,429			2,162			16,559			3,207			5,533			4,381			3,438

Operating Cash Flow

Crude Oil and Natural Gas Liquids
Foster Creek and Christina Lake		596			220												421			36
Canadian Plains		941			275												1,508			180
Natural Gas		1,798			389												2,099			464
Other Upstream Operations		50			14												63			1

		3,385			898												4,091			681
Downstream		310			11												(241	)		(580	)

Operating Cash Flow		3,695			909												3,850			101


Cash Flow Information

Cash from Operating Activities		3,496			831			1,318			922			425			2,687			30			884			993			780
Deduct (Add back):
Net change in other assets and liabilities		(23	)		(13	)		(3	)		(4	)		(3	)		(89	)		1			(9	)		(47	)		(34	)
Net change in non-cash working capital		1,047			619			480			115			(167	)		(312	)		203			(230	)		(188	)		(97	)

Cash Flow ⁽¹⁾		2,472			225			841			811			595			3,088			(174	)		1,123			1,228			911
Per share — Basic		3.29			0.30			1.12			1.08			0.79			4.12			(0.23	)		1.50			1.64			1.21
— Diluted		3.29			0.30			1.12			1.08			0.79			4.11			(0.23	)		1.50			1.63			1.21
Operating Earnings ⁽²⁾		1,312			152			382			447			331			1,629			(123	)		611			710			431
Per share — Diluted		1.74			0.20			0.51			0.59			0.44			2.17			(0.16	)		0.81			0.95			0.57
Net Earnings		648			24			63			149			412			2,368			380			1,299			522			167
Per share — Basic		0.86			0.03			0.08			0.20			0.55			3.16			0.51			1.73			0.70			0.22
— Diluted		0.86			0.03			0.08			0.20			0.55			3.15			0.51			1.73			0.69			0.22

Effective Tax Rates using
Net Earnings		31.8	%														23.4	%
Operating Earnings, excluding divestitures		25.1	%														22.5	%
Canadian Statutory Rate		29.2	%														29.7	%

Foreign Exchange Rates (US$ per C$1)
Average		0.876			0.947			0.911			0.857			0.803			0.938			0.825			0.961			0.990			0.996
Period end		0.956			0.956			0.933			0.860			0.794			0.817			0.817			0.944			0.982			0.973


⁽¹⁾		Cash Flow is a non-GAAP measure defined as Cash from Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the Consolidated Statement of Cash Flows.

⁽²⁾		Operating Earnings is a non-GAAP measure defined as Net Earnings excluding the after-tax gain/loss on discontinuance, after-tax effect of unrealized mark-to-market accounting gains/losses on derivative instruments, after-tax gains/losses on translation of U.S. dollar denominated Notes issued from Canada, after-tax foreign exchange gains/losses on settlement of intercompany transactions, future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates.


	2009			2008
Financial Metrics
Debt to Capitalization⁽¹⁾		28	%		28	%
Debt to Adjusted EBITDA ^{(1, 2)}		1.2	x		0.7	x
Return on Capital Employed^{(1, 2)}		8	%		22	%
Return on Common Equity ⁽²⁾		7	%		30	%


⁽¹⁾		Calculated using Debt defined as the current and long-term portions of Long-Term Debt.

⁽²⁾		Calculated on a trailing twelve-month basis.


	December
Common Share Information	2009
Common Shares Outstanding (millions) ⁽¹⁾
Period end		751.3
Average — Basic		751.0
Average — Diluted		751.4

Price Range ($ per share)
TSX — C$
High		27.18
Low		24.68
Close		26.50

NYSE — US$
High		25.70
Low		23.37
Close		25.20
Dividends Paid (US$ per share)⁽²⁾		0.20

Share Volume Traded (millions)		83.5


⁽¹⁾		Cenovus Common Shares were issued under terms of the arrangement on November 30, 2009 and began trading on December 3, 2009 (TSX) and December 9, 2009 (NYSE).

⁽²⁾		Dividend paid in December reflects an amount determined in connection with the Arrangement with EnCana Corporation based on carve-out earnings and cash flows.



Cenovus Energy Inc.		89
Annual Financials 2009		Supplemental Information (prepared in US$)

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (continued)


	2009						2008
Net Capital Investment (US$ millions)	Year			Q4			Year			Q4
Capital Investment
Upstream Canada
Foster Creek		231			73			336			74
Christina Lake		198			61			218			63
Canadian Plains		478			110			872			272
Other		47			4			90			22

		954			248			1,516			431
Downstream Refining		907			212			478			168
Corporate		31			21			52			27

Capital Investment		1,892			481			2,046			626

Acquisitions		3			2			—			—
Divestitures		(209	)		(208	)		(47	)		—

Net Acquisition and Divestiture Activity		(206	)		(206	)		(47	)		—

Net Capital Investment		1,686			275			1,999			626

Operating Statistics — After Royalties


	2009										2008
Upstream Production Volumes	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Crude Oil and Natural Gas Liquids (bbls/d)
Heavy Oil
Foster Creek		36,654		45,035		38,954		34,249		28,170		25,947		28,955		26,979		21,038		26,770
Christina Lake		6,527		7,022		6,097		6,428		6,559		4,236		6,113		4,568		3,633		2,606
Integrated Oil — Other		2,553		1,921		4,401		1,800		2,069		2,729		2,133		2,273		3,009		3,514
Canadian Plains		32,143		30,338		31,684		31,508		35,097		35,029		32,843		34,655		34,618		38,029
Light and Medium Oil
Canadian Plains		30,721		29,110		30,676		31,183		31,946		31,128		32,147		30,134		30,479		31,752
Natural Gas Liquids ⁽¹⁾
Canadian Plains		1,186		1,164		1,216		1,162		1,201		1,181		1,126		1,147		1,189		1,262

Total Crude Oil and Natural Gas Liquids		109,784		114,590		113,028		106,330		105,042		100,250		103,317		99,756		93,966		103,933

Natural Gas (MMcf/d)
Integrated Oil — Other		49		31		51		72		42		63		59		61		67		65
Canadian Plains		775		734		775		792		800		842		820		831		856		860

Total Natural Gas Production		824		765		826		864		842		905		879		892		923		925


⁽¹⁾		Natural gas liquids include condensate volumes.


Average Royalty Rates	2009															2008
(excluding impact of realized financial hedging)	Year			Q4			Q3			Q2			Q1			Year			Q4			Q3			Q2			Q1
Crude Oil — Foster Creek		2.7	%		3.9	%		3.0	%		1.5	%		1.4	%		1.1	%		0.7	%		1.6	%		1.0	%		1.1	%
Crude Oil — Christina Lake		2.3	%		3.6	%		2.9	%		1.6	%		1.0	%		1.0	%		1.0	%		1.1	%		1.0	%		1.1	%
Crude Oil — Pelican Lake/Weyburn		19.4	%		22.8	%		19.9	%		19.2	%		15.7	%		20.2	%		16.1	%		21.8	%		22.8	%		20.1	%
Crude Oil — Other		7.8	%		8.4	%		9.0	%		6.1	%		5.4	%		9.0	%		8.1	%		10.2	%		8.7	%		8.9	%
Natural Gas		1.5	%		3.9	%		0.5	%		-0.9	%		2.8	%		5.1	%		2.9	%		5.8	%		6.4	%		5.3	%
Natural Gas Liquids		1.6	%		1.6	%		2.1	%		1.9	%		1.0	%		1.8	%		2.8	%		1.7	%		1.2	%		1.6	%

	2009															2008
Downstream Refining	Year			Q4			Q3			Q2			Q1			Year			Q4			Q3			Q2			Q1
Refinery Operations ⁽¹⁾
Crude oil capacity (Mbbls/d)		452			452			452			452			452			452			452			452			452			452
Crude oil runs (Mbbls/d)		394			348			425			404			398			423			434			412			437			408
Crude utilization (%)		87	%		77	%		94	%		89	%		88	%		93	%		96	%		91	%		97	%		90	%
Refined products (Mbbls/d)		417			370			451			428			421			448			456			438			464			435


(1)		Represents 100% of the Wood River and Borger refinery operations.



Cenovus Energy Inc.		90
Annual Financials 2009		Supplemental Information (prepared in US$)

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics — After Royalties (continued)


Per-unit Results	2009													2008
(US$, excluding impact of realized financial hedging)	Year			Q4		Q3			Q2		Q1			Year		Q4		Q3		Q2			Q1
Crude Oil — Heavy — Foster Creek ($/bbl)
Price⁽¹⁾		50.07			60.41		56.76			46.98		27.08			62.88		17.97		92.07		95.64			59.95
Production and mineral taxes		—			—		—			—		—			—		—		—		—			—
Transportation and selling		2.27			1.69		2.33			3.02		2.19			2.21		1.90		1.98		2.63			2.46
Operating		10.75			10.28		10.19			10.25		12.96			14.38		10.08		14.42		19.90			14.90

Netback		37.05			48.44		44.24			33.71		11.93			46.29		5.99		75.67		73.11			42.59

Crude Oil — Heavy — Christina Lake ($/bbl)
Price⁽²⁾		47.66			54.06		59.28			49.25		26.08			59.63		29.61		86.06		81.02			56.94
Production and mineral taxes		—			—		—			—		—			—		—		—		—			—
Transportation and selling		2.78			0.95		5.06			2.46		2.74			3.34		2.78		2.81		3.62			5.25
Operating		14.76			17.75		14.41			11.92		14.78			22.79		14.07		22.24		30.92			33.66

Netback		30.12			35.36		39.81			34.87		8.56			33.50		12.76		61.01		46.48			18.03

Crude Oil — Heavy — Canadian Plains ($/bbl)
Price		48.49			57.48		57.30			48.22		31.34			74.08		31.30		95.86		98.65			70.44
Production and mineral taxes		(0.01	)		0.02		(0.01	)		0.02		(0.07	)		0.03		0.06		0.07		(0.10	)		0.07
Transportation and selling		1.12			0.81		1.10			1.37		1.17			1.60		1.13		2.42		1.60			1.29
Operating		9.80			13.24		8.74			9.61		7.82			9.04		7.17		7.62		11.30			9.93

Netback		37.58			43.41		47.47			37.22		22.42			63.41		22.94		85.75		85.85			59.15

Crude Oil — Heavy — Total ($/bbl)
Price		49.24			58.81		57.14			47.90		29.08			68.98		25.39		94.05		96.35			66.12
Production and mineral taxes		0.03			0.03		0.05			0.05		(0.03	)		0.07		0.05		0.10		0.02			0.12
Transportation and selling		1.84			1.32		2.07			2.26		1.74			1.97		1.62		2.29		2.10			1.91
Operating		10.72			11.94		9.76			10.42		10.71			12.26		9.13		11.62		15.92			12.89

Netback		36.65			45.52		45.26			35.17		16.66			54.68		14.59		80.04		78.31			51.20

Light and Medium Oil — Canadian Plains ($/bbl)
Price		55.29			67.84		61.76			55.00		37.51			84.84		41.60		107.59		107.08			85.90
Production and mineral taxes		2.14			1.74		2.26			1.86		2.69			3.33		2.05		4.70		3.97			2.72
Transportation and selling		0.87			0.71		0.76			1.02		0.96			1.20		0.96		1.41		1.27			1.16
Operating		10.04			11.16		10.22			9.35		9.50			10.56		8.28		9.40		13.05			11.60

Netback		42.24			54.23		48.52			42.77		24.36			69.75		30.31		92.08		88.79			70.42

Crude Oil — Total ⁽¹⁾ ⁽²⁾ ($/bbl)
Price		50.96			61.13		58.39			50.00		31.75			73.95		30.31		98.26		99.82			72.36
Production and mineral taxes		0.63			0.47		0.65			0.59		0.83			1.09		0.66		1.53		1.29			0.94
Transportation and selling		1.56			1.17		1.72			1.89		1.50			1.73		1.42		2.02		1.83			1.68
Operating		10.53			11.74		9.89			10.10		10.33			11.73		8.87		10.93		14.99			12.48

Netback		38.24			47.75		46.13			37.42		19.09			59.40		19.36		83.78		81.71			57.26

Natural Gas Liquids — Canadian Plains ($/bbl)
Netback		43.51			55.89		44.88			38.36		34.86			78.91		45.13		98.34		96.34			75.09

Total Liquids ($/bbl)
Price		50.87			61.08		58.25			49.88		31.78			74.00		30.47		98.26		99.77			72.39
Production and mineral taxes		0.62			0.47		0.64			0.58		0.82			1.08		0.65		1.51		1.28			0.93
Transportation and selling		1.55			1.15		1.70			1.87		1.48			1.71		1.40		2.00		1.81			1.66
Operating		10.41			11.62		9.78			9.99		10.21			11.59		8.78		10.80		14.81			12.33

Netback		38.29			47.84		46.13			37.44		19.27			59.62		19.64		83.95		81.87			57.47

Total Natural Gas⁽³⁾ ($/Mcf)
Price		3.60			3.95		2.86			3.22		4.41			7.76		5.63		8.66		9.50			7.19
Production and mineral taxes		0.04			0.03		0.04			0.06		0.04			0.11		0.06		0.16		0.16			0.06
Transportation and selling		0.14			0.12		0.14			0.13		0.15			0.24		0.21		0.25		0.24			0.25
Operating		0.76			0.80		0.77			0.70		0.78			0.84		0.72		0.62		1.00			1.03

Netback		2.66			3.00		1.91			2.33		3.44			6.57		4.64		7.63		8.10			5.85

Total⁽⁴⁾($/BOE)
Price		34.58			41.36		35.80			32.36		28.69			57.55		32.39		70.37		73.39			54.82
Production and mineral taxes		0.42			0.31		0.42			0.46		0.49			0.83		0.47		1.19		1.07			0.58
Transportation and selling		1.14			0.93		1.24			1.25		1.14			1.54		1.34		1.69		1.57			1.57
Operating⁽³⁾		7.17			8.02		6.97			6.69		7.00			7.68		6.19		6.54		9.38			8.62

Netback		25.85			32.10		27.17			23.96		20.06			47.50		24.39		60.95		61.37			44.05


⁽¹⁾		The Foster Creek price for 2008 includes the impact of the write-down of condensate inventories to net realizable value (2008 — $4.68/bbl; Q4 2008 — $12.53/bbl; Q3 2008 — $3.59/bbl).

⁽²⁾		The Christina Lake price for 2008 includes the impact of the write-down of condensate inventories to net realizable value (2008 — $0.25/bbl; Q4 2008 — $0.84/bbl).

⁽³⁾		Natural gas — Total includes natural gas from the Athabasca property.

⁽⁴⁾		2009 year-to-date operating costs include costs related to long-term incentives of $0.09/BOE (2008 — cost recovery of $0.06/BOE).

Impact of Realized Financial Hedging


Liquids ($/bbl)	0.98	(0.05	)	(0.01	)	1.39	2.86	(6.07	)	2.71	(8.85	)	(12.50	)	(6.63	)
Natural Gas ($/Mcf)	3.22	2.24		4.04		3.68	2.82	(0.30	)	1.07	(1.15	)	(1.41	)	0.34

Total ($/BOE)	11.18	7.07		13.25		13.24	11.02	(3.50	)	4.85	(7.69	)	(10.01	)	(1.43	)



Cenovus Energy Inc.		91
Annual Financials 2009		Supplemental Information (prepared in US$)

Corporate Information


Corporate Officers ⁽¹⁾ Brian C. Ferguson President & Chief Executive Officer John K. Brannan Executive Vice-President (President, Integrated Oil Division) Harbir S. Chhina Executive Vice-President, Enhanced Oil Development & New Resource Plays Kerry D. Dyte Executive Vice-President, General Counsel & Corporate Secretary Judy A. Fairburn Executive Vice-President, Environment & Strategic Planning Sheila M. McIntosh Executive Vice-President, Communications & Stakeholder Relations Ivor M. Ruste Executive Vice-President & Chief Financial Officer Neil W. Robertson Comptroller Wayne R. Thomas Treasurer Donald T. Swystun Executive Vice-President (President, Canadian Plains Division) Hayward J. Walls Executive Vice-President, Organization & Workplace Development (1) Divisional title in italics.		Board of Directors ⁽¹⁾ Michael A. Grandin ^(2,5,9) Chair Calgary, Alberta Ralph S. Cunningham ^(2,4,5,7) Houston, Texas Patrick D. Daniel ^(2,3,4,5) Calgary, Alberta Ian W. Delaney ^(2,4,5,7) Toronto, Ontario Brian C. Ferguson ⁽⁸⁾ Calgary, Alberta Valerie A. A. Nielsen ^(2,3,5,6) Calgary, Alberta Charles M. Rampacek ^(5,6,7) Dallas, Texas Colin Taylor ^(3,4,5) Toronto, Ontario Wayne G. Thomson ^(2,5,6,7) Calgary, Alberta (1) Each of the directors became members of our Board pursuant to the Arrangement. (2) Former director of EnCana. (3) Member of the Audit Committee. (4) Member of the Human Resources and Compensation Committee. (5) Member of the Nominating and Corporate Governance Committee. (6) Member of the Reserves Committee. (7) Member of the Safety, Environment and Responsibility Committee. (8) As an officer and a non-independent director, Mr. Ferguson is not a member of any of the Committees of our Board. (9) Ex-officio non-voting member of all other Committees of our Board. As an ex-officio non-voting member, Mr. Grandin attends as his schedule permits and may vote when necessary to achieve a quorum.



Cenovus Energy Inc.		92
Annual Financials 2009		Corporate Information


Corporate Information

Cenovus Head Office		Auditors

4000, 421 — 7 Avenue S.W. PO Box 766 Calgary, Alberta, Canada T2P 0M5 Phone: 403-766-2000 www.cenovus.com Transfer Agents & Registrar Common Shares CIBC Mellon Trust Company Calgary, Montreal & Toronto BNY Mellon Shareowner Services Jersey City, New Jersey Shareholders are encouraged to contact CIBC Mellon Trust Company for information regarding their security holdings. They can be reached throughout North America by phoning 1-866-332-8898 (English & French) and outside North America by phoning 1-416-643-5850 or by facsimile at 1-416-643-5501. CIBC Mellon Trust Company PO Box 7010 Adelaide Street Postal Station Toronto, Ontario, Canada M5C 2W9 www.cibcmellon.com Trustee & Registrars The Bank of New York 4.500% Senior Notes 5.700% Senior Notes 6.750% Senior Notes New York, New York		PricewaterhouseCoopers LLP Chartered Accountants Calgary, Alberta Independent Qualified Reserve Evaluators GLJ Petroleum Consultants Ltd. Calgary, Alberta McDaniel & Associates Consultants Ltd. Calgary, Alberta Stock Exchanges Common Shares (CVE) Toronto Stock Exchange (TSX) New York Stock Exchange (NYSE) NYSE Statement of Differences As a Canadian company listed on the New York Stock Exchange (“NYSE”), Cenovus is not required to comply with most of the NYSE corporate governance standards and instead may comply with Canadian corporate governance requirements. Cenovus is, however, required to disclose the significant differences between its corporate governance practices and those required to be followed by U.S. domestic companies under the NYSE corporate governance standards. Except as summarized on our website, www.cenovus.com, we are in compliance with the NYSE corporate governance standards in all significant respects.



Cenovus Energy Inc.		93
Annual Financials 2009		Corporate Information

Investor Information


Annual Information Form (Form 40-F) Cenovus’s Annual Information Form (AIF) is filed with the securities regulators in Canada and the United States. Under the Multi-Jurisdictional Disclosure System, Cenovus’s AIF is filed as Form 40-F with the United States Securities and Exchange Commission. These documents can be obtained via www.sedar.com or www.sec.gov (for the Form 40-F), or www.cenovus.com. Shareholder Account Matters To change your address, transfer shares, eliminate duplicate mailings, deposit dividends directly into accounts at financial institutions in Canada that provide electronic fund-transfer services, etc., please contact CIBC Mellon Trust Company.		Cenovus Website www.cenovus.com Cenovus’s website contains corporate and investor information including, but not limited to: Current stock prices Financial Reports EnCana Information Circular Relating to the Arrangement News releases Investor presentations Dividend information Shareholder support information Additional information may be obtained from: Cenovus Energy Inc. Investor Relations, Communications & Stakeholder Relations 4000, 421 — 7 Avenue S.W. PO Box 766 Calgary, Alberta, Canada T2P 0M5 Phone: 403-766-7744 investor.relations@cenovus.com Investor inquiries should be directed to: Paul Gagne Vice-President, Investor Relations 403-766-4737 paul.gagne@cenovus.com Susan Grey Manager, Investor Relations 403-766-4751 susan.grey@cenovus.com James Fann Analyst, Investor Relations 403-766-6700 james.fann@cenovus.com Media inquiries should be directed to: Rhona DelFrari Manager, Media Relations 403-766-4740 rhona.delfrari@cenovus.com



Cenovus Energy Inc.		94
Annual Financials 2009		Investor Information